SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
[ X ] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 1996
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15 (d)
OF THE SECURITIES EXCHANGE ACT OF 1934
Commission file number 1-8858
UNITIL CORPORATION
(Exact name of registrant as specified in its charter)
New Hampshire 02-0381573
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
6 Liberty Lane West, Hampton, New Hampshire 03842-1720
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (603) 772-0775
Securities registered pursuant to Section 12(b) of the Act:
Title of Each Class Name of Exchange on Which Registered
Common Stock, No Par Value American Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: NONE
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to
such filing requirements for the past 90 days.
Yes X No
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to
the best of registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendments to this Form 10-K [ X ]
Based on the closing price of March 1, 1997, the aggregate market value of
common stock held by non-affiliates of the registrant was $87,345,040.
The number of common shares outstanding of the registrant was 4,394,719 as
of March 1, 1997.
Documents Incorporated by Reference:
Portions of the Proxy Statement relating to the Annual Meeting of
Shareholders to be held April 17, 1997, are incorporated by reference into
Part III of this Report.
UNITIL CORPORATION
FORM 10-K
For the Fiscal Year Ended December 31, 1996
Table of Contents
Item Description Page
PART I
1. Business
The Unitil System ....................................... 2
Utility Operations ....................................... 2
Rates and Regulation ....................................... 3
Electric Utility Industry Restructuring and Competition ....... 5
Gas Utility Industry Restructuring and Competition .. ....... 7
Electric Power Supply ....................................... 8
Gas Supply ....................................... 9
Environmental Matters ....................................... 10
Capital Requirements ....................................... 10
Financing Activities ....................................... 11
Employees ............................................... 11
Executive Officers of the Registrant ....................... 12
2. Properties ............................................... 13
3. Legal Proceedings ....................................... 14
4. Submission of Matters to a Vote of Securities Holders ........ 14
PART II
5. Market for Registrant's Common Equity and Related Stockholder Matters 15
6. Selected Financial Data ....................................... 16
7. Management's Discussion and Analysis of Financial Condition and
Results of Operations ....................................... 17
8. Financial Statements and Supplementary Data ................ 25
9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure ........................................... 43
PART III
10. Directors and Executive Officers of the Registrant ....... 44
11. Executive Compensation ....................................... 44
12. Security Ownership of Certain Beneficial Owners and Management 44
13. Certain Relationships and Related Transactions ............... 44
PART IV1
14. Exhibits, Financial Statement Schedules and Reports on Form 8-K 45
Signatures ................................................... 52
Schedule VIII Valuation and Qualifying Accounts and Reserves ... 53
Exhibit 11.1 Computation in Support of Earnings per Share
Exhibit 12.1 Computation in Support of Ratio of Earnings to
Fixed Charges
Exhibit 21.1 Subsidiaries of Registrant
Exhibit 27 Financial Data Schedule
Exhibit 99.1 1997 Proxy Statement
PART I
Item 1. Business.
The Unitil System
Unitil Corporation (Unitil or the Company) was incorporated under
the laws of the State of New Hampshire in 1984. Unitil is a registered
public utility holding company under the Public Utility Holding Company Act
of 1935 (the 1935 Act), and is the parent company of the Unitil System. The
following company's are wholly owned subsidiaries of Unitil, which together
make up the Unitil System:
State and
Year of
Unitil Corporation Subsidiaries Organization Principal Type of Business
Concord Electric Company (CECo) NH - 1901 Retail Electric Distribution
Utility
Exeter & Hampton Electric NH - 1908 Retail Electric Distribution
Company (E&H) Utility
Fitchburg Gas and Electric MA - 1852 Retail Electric & Gas
Light Company(FG&E) Distribution Utility
Unitil Power Corp. NH - 1984 Wholesale Electric Power
(Unitil Power) Utility
Unitil Realty Corp. NH - 1986 Real Estate Management
(Unitil Realty)
Unitil Service Corp. NH - 1984 System Service Company
(Unitil Service)
Unitil Resources, Inc. NH - 1993 Energy Marketing and Services
(Unitil Resources)
The Unitil System's principal business is the retail sale and
distribution of electricity and related services in several cities and towns
in the seacoast and capital city areas of New Hampshire and both electricity
and gas and related services in north central Massachusetts, through Unitil's
three wholly owned retail distribution utility subsidiaries (CECo, E&H and
FG&E, collectively referred to as the Retail Distribution Utilities). The
Company's wholesale electric power utility subsidiary, Unitil Power Corp.,
principally provides all the electric power supply requirements to CECo and
E&H for resale at retail, and also engages in various other wholesale
electric power services with affiliates and non-affiliates throughout the New
England region.
Unitil has three additional wholly owned subsidiaries: Unitil Realty
Corp. (Unitil Realty), Unitil Service Corp. (Unitil Service) and Unitil
Resources Inc. (Unitil Resources). Unitil Realty owns and manages the
Company's corporate office building and property located in Hampton, New
Hampshire and leases this facility at cost to Unitil Service under a long-
term lease arrangement. Unitil Service provides, at cost, centralized
management, administrative, accounting, financial, engineering, information
systems, regulatory, planning, procurement, and other services to the Unitil
System companies. Unitil Resources is the Company's wholly owned non-
utility subsidiary and has been authorized by the Securities and Exchange
Commission, pursuant to the rules and regulations of the 1935 Act, to engage
in business transactions as a competitive marketer of electricity, gas and
other energy commodities in wholesale and retail markets, and to provide
energy, brokering, consulting and management related services within the
United States.
Utility Operations
CECo is engaged principally in the distribution and sale of
electricity at retail to approximately 26,300 customers in the City of
Concord, which is the state capitol, and twelve surrounding towns, all in
New Hampshire. CECo's service area consists of approximately 240 square
miles in the Merrimack River Valley of south central New Hampshire. The
service area includes the City of Concord and major portions of the
surrounding towns of Bow, Boscawen, Canterbury, Chichester, Epsom, Salisbury
and Webster, and limited areas in the towns of Allenstown, Dunbarton,
Hopkinton, Loudon and Pembroke.
The State of New Hampshire's government operations are located within
CECo's service area, including the executive, legislative, judicial branches
and offices and facilities for all major state government services. In
addition, CECo's service area is a retail trading center for the north
central part of the state and has over sixty diversified businesses relating
to insurance, printing, electronics, granite, belting, plastic yarns,
furniture, machinery, sportswear and lumber. Of CECo's 1996 retail electric
revenues, approximately 34% was derived from residential sales, 54% from
commercial, government and nonmanufacturing sales, and 12% from industrial/
manufacturing sales.
E&H is engaged principally in the distribution and sale of electricity
at retail to approximately 37,300 customers in the towns of Exeter and
Hampton and in all or part of sixteen surrounding towns, all in New Hampshire.
E&H's service area consists of approximately 168 square miles in southeastern
New Hampshire. The service area includes all of the towns of Atkinson,
Danville, East Kingston, Exeter, Hampton, Hampton Falls, Kensington,
Kingston, Newton, Plaistow, Seabrook, South Hampton and Stratham, and
portions of the towns of Derry, Brentwood, Greenland, Hampstead and North
Hampton.
Commercial and industrial customers served by E&H are quite
diversified and include retail stores, shopping centers, motels, farms,
restaurants, apple orchards and office buildings, as well as manufacturing
firms engaged in the production of sportswear, automobile parts and
electronic components. It is estimated that there are over 150,000 daily
summer visitors to E&H's territory, which includes several popular resort
areas and beaches along the Atlantic Ocean. Of E&H's 1996 retail electric
revenues, approximately 47% was derived from residential sales, 43% from
commercial and nonmanufacturing sales, 10% from industrial/manufacturing
sales.
FG&E is engaged principally in the distribution and sale of both
electricity and natural gas in the City of Fitchburg and several surrounding
communities. FG&E's service area encompasses approximately 170 square miles
in north central Massachusetts.
Electricity is supplied and distributed by FG&E to approximately
25,600 customers in the communities of Fitchburg, Ashby, Townsend and
Lunenburg. FG&E's industrial customers include paper manufacturing and
allied products companies, rubber and plastics manufacturers, chemical
products companies and printing, publishing and allied industries. Of FG&E's
1996 electric revenues, approximately 33% was derived from residential sales,
33% from commercial and nonmanufacturing sales, and 34% from industrial/
manufacturing sales.
Natural gas is supplied and distributed by FG&E to approximately
14,800 customers in the communities of Fitchburg, Lunenburg, Townsend, Ashby,
Gardner and Westminster, all located in Massachusetts. Of FG&E's 1996 gas
operating revenues, approximately 51% was derived from residential sales, 23%
from commercial sales, 11% from firm sales to industrial customers, and 16%
from interruptible sales (which are sales to duel-fuel customers who possess
alternative competitive energy sources, such as fuel oil, and who typically
use gas during the non-heating season on an as-available basis). FG&E's
industrial gas revenue is primarily derived from firm sales to paper
manufacturing and allied products companies, fabricated metal products
manufacturers, rubber and plastics manufacturers, primary iron manufacturers
and other miscellaneous industries.
Natural gas sales in New England are seasonal, and the Company's
results of operations reflect this seasonality. Accordingly, results of
operations are typically positively impacted by gas operations during the
five heating season months from November through March of the following year.
Electric sales in New England are far less seasonal than natural gas sales;
however, the highest usage typically occurs in the summer and winter months
due to air conditioning and heating requirements, respectively. The Unitil
System is not dependent on a single customer or a few customers for its
electric and gas sales.
(For details on the Unitil System's Results of Operations see Part II,
Section 7 herein.)
Rates and Regulation
The Company is registered with the Securities and Exchange Commission
(SEC) as a holding company under the 1935 Act, and it and its subsidiaries
are subject to the provisions of the 1935 Act. Accordingly, the Securities
and Exchange Commission (SEC) has jurisdiction over Unitil and its
subsidiaries with respect to, among other things, securities issues, sales
and acquisitions of securities and utility assets, intercompany loans,
services performed by and for affiliated companies, certain accounts and
records, and involvement in non utility operations. The Company and its
subsidiaries, where applicable, are subject to regulation by the Federal
Energy Regulatory Commission (FERC), the New Hampshire Public Utilities
Commission (NHPUC) and the Massachusetts Department of Public Utilities
(MDPU) with respect to rates, adequacy of service, issuance of securities,
accounting and other matters. Unitil Power, as a wholesale utility, is
subject to rate regulation by the FERC. Both CECo and E&H, as retail electric
utilities in New Hampshire, are subject to rate regulation by the NHPUC, and
FG&E is subject to MDPU regulation with respect to gas and electric retail
rates, and FERC regulation with respect to New England Power Pool (NEPOOL)
interchanges and other wholesale sales of electricity.
Current Rate Regulation--- The revenues of Unitil's Retail Distribution
Utilities are collected pursuant to rates on file with the NHPUC, the MDPU
and, to a minor extent, the FERC. In general, the Retail Distribution
Companies current retail rates are comprised of a base rate component,
established during comprehensive base rate cases, and various periodic rate
adjustment mechanisms, which track and reconcile particular expense elements
with associated collected revenues. The last comprehensive regulatory
proceedings to increase base rates for the Unitil's Retail Distribution
Utilities were in 1985 for CECo, 1984 for FG&E, and 1982 for E&H. The
majority of the Unitil System's utility operating revenues are presently
collected under various rate adjustment mechanisms, including revenues
collected from customers for fuel, purchased power, cost of gas, and demand-
side management program costs.
The Unitil System Agreement (System Agreement), as approved by the
FERC, governs wholesale sales by Unitil Power to its New Hampshire retail
distribution affiliates, CECo and E&H, and provides for recovery by Unitil
Power of all costs incurred in the provision of service. Unitil Power has
continued to adjust its wholesale rates every six months in accordance with
the System Agreement, and CECo and E&H have continued to file corresponding
semiannual changes in their retail fuel and purchased power adjustment
clauses with the NHPUC which have been routinely approved.
FG&E also files a quarterly electric fuel charge and a semiannual gas
adjustment factor with the MDPU for approval to adjust its rates for changes
in fuel and gas related costs. Although all of FG&E's electric fuel costs
and the largest portion of its purchased power costs are fully recovered
under the Department's Electric Fuel Charge regulations, FG&E's electric
generation entitlements are subject to annual performance reviews.
Performance targets are filed by FG&E in advance and approved by the
Department, and in January of each year FG&E files data on actual unit
performance for the prior November to October period. The Department will
investigate reasons why units failed to meet target performance criteria,
and has in some cases disallowed recovery of replacement power costs for
unplanned outages which the Department deemed to be due to imprudent
operations or actions.
FG&E's gas costs are recovered through a cost of gas adjustment (CGA)
mechanism, through which firm gas customers pay the costs incurred for
procuring and transporting gas to FG&E's local distribution system for
delivery to customers. FG&E gas operations have been incurring FERC-
approved transition charges from interstate pipeline suppliers, resulting
from the transition to a comprehensive set of new regulations under FERC
Order 636. These costs have been recovered directly from FG&E's gas customers
through the CGA mechanism, as authorized by the MDPU.
Millstone Unit No. 3 --- FG&E has a 0.217% nonoperating ownership in the
Millstone Unit No. 3 (Millstone 3) nuclear generating unit which supplies it
with 2.49 megawatts (MW) of electric capacity. In January 1996 the Nuclear
Regulatory Commission (NRC) placed Millstone 3 on its watch list as a
Category 2 facility, which calls for increased NRC inspection attention. In
March 1996 the NRC requested additional information about the operation of
the unit from Northeast Utilities companies (NU), which operate the unit. As
a result of an engineering evaluation completed by NU, Millstone 3 was taken
out of service on March 30, 1996. The NRC later informed NU, in a letter
dated June 28, 1996, that it had reclassified Millstone 3 as a Category 3
facility. The NRC assigns this rating to plants which it deems to have
significant weaknesses that warrant maintaining the plant in shutdown
condition until the operator demonstrates that adequate programs have been
established and implemented to ensure substantial improvement in the
operation of the plant. The NRC's letter also informed NU that this
designation would require the NRC staff to obtain NRC approval by vote prior
to a restart of the unit. The other Millstone nuclear units are also out of
service and listed as Category 3 facilities.
The Company cannot predict when Millstone 3 will be allowed by the
NRC to restart, but believes that the unit will remain shut down for a
protracted period of time. During the period that Millstone 3 is out of
service, FG&E will continue to incur its proportionate share of the unit's
ongoing Operations and Maintenance (O&M) costs, and may incur additional O&M
costs and capital expenditures to meet NRC requirements. FG&E will also
incur costs to replace the power that was expected to be generated by the
unit. During the outage, FG&E has been incurring approximately $35,000 per
month in replacement power costs, and has been recovering these costs
through its fuel adjustment clause, which will be subject to review and
approval by the MDPU.
SFAS No. 71 --- The Company follows the provisions of Statement of Financial
Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain
Types of Regulation, " requiring the Company to record the financial
statement effects of the rate regulation to which the Company is currently
subject. Future regulatory changes could result in the Company no longer
meeting the provisions of SFAS 71 for all or part of its business; thereby
requiring the elimination of the financial statement effect of regulation
for the portion of the business.
(For a discussion of utility rates and regulation under a more competitive
environment, see the following sections on Electric Utility Industry
Restructuring and Competition, and Gas Utility Restructuring and Competition)
Electric Utility Industry Restructuring and Competition
The electric utility industry is undergoing a period of rapid change.
Most prominent among these changes is the introduction of retail competition
and the congruous legislative and regulatory initiatives that are designed
to give retail customers the ability to choose, for the first time, their
own electric energy supplier. Unitil has been preparing for this
restructuring by developing transition plans that will move its utility
subsidiaries into this new market structure in a way that will ensure
fairness in the treatment of the Company's assets and obligations that are
dedicated to the current regulated franchises and, at the same time, provide
choice of energy suppliers for all customers. Simultaneous with this
transition process for Unitil's regulated utilities, the Company is moving
to position its competitive market subsidiary, Unitil Resources, to pursue
growth areas both within and beyond the Company's traditional franchises in
all energy-related sectors.
Unitil's electric utility operations have sold and distributed
electricity and related services at retail in New Hampshire and Massachusetts,
within the respective franchise territories of the Retail Distribution
Utilities. However, under current legislative and regulatory electric
industry restructuring proposals and plans in both New Hampshire and
Massachusetts, the energy supply function would be separated form the
delivery of that energy to customers. Under this new industry structure,
Unitil's Retail Distribution Utilities would no longer sell electricity to
their customers. Instead, as early as January 1, 1998 retail customers
could purchase electricity from a competitive supplier of their choice, with
the Retail Distribution Utilities remaining responsible for providing
electric distribution services only over their "wire and poles" at regulated
rates. Electric power would be provided by competitive market power
generators and energy marketers. The Retail Distribution Utilities may
continue to have an obligation to provide and/or arrange for "default"
energy supply services to customers who either elect not to choose a
competitive power supplier or who are without a competitive energy supplier
under certain circumstances. However, the role of the Retail Distribution
Company as the sole supplier of their customers' electric power supply would
no longer exist.
Under this new competitive market structure, utilities that have
power supply obligations and commitments face the risk that market prices
may not be sufficient to recover the costs of these commitments which were
incurred to supply customers under a regulated industry structure. The
amount by which power supply related costs exceed market prices for this
power is commonly referred to as "stranded costs". Unitil's New Hampshire
based Retail Distribution Utilities, CECo and E&H, presently purchase all
their electric energy requirements at cost under a wholesale power agreement
with Unitil's wholesale power company, Unitil Power, and resell it to their
customers. Under New Hampshire's restructuring plan, CECo and E&H are
required to terminate the wholesale power agreement with Unitil Power and
may seek authorization to fully recover their stranded costs which are
related to their purchase power obligations through a wires access or
transition charge to retail customers. FG&E, Unitil's Massachusetts based
distribution subsidiary, has purchased power obligations with nonaffiliated
companies and also has non operating ownership interest in three joint-owned
generating units. Current legislative and regulatory industry restructuring
proposals in Massachusetts also provide for the reasonable recovery of any
stranded costs related to FG&E's power supply obligations.
Regulatory activity in both New Hampshire and Massachusetts has
focused on deregulating the retail sale of electric energy. In both states,
January 1, 1998 has been targeted as the beginning of competition, or "Choice
Date." Under these restructuring proposals, customers would be allowed to
choose their supplier of electricity from the competitive market, and have
their local utility deliver that electricity over its distribution systems
at regulated rates.
New Hampshire --- In New Hampshire, House Bill 1392 (HB 1392) was signed
into law by the Governor in May 1996. HB 1392 establishes principles,
standards and a timetable for the NHPUC to implement full, open retail
electric competition as early as January 1, 1998, but no later than July 1,
1998. The bill also directs the NHPUC to set interim access charges for the
recovery of above market "stranded" power supply costs and to make a final
determination on these access charges within two years of implementation of
full competition.
On February 28, 1997, the NHPUC issued its Final Plan for
restructuring the electric utility industry in New Hampshire. Concurrently,
the NHPUC issued five separate orders establishing interim stranded cost
charges for each of the state's electric utilities, including Concord
Electric Company (CECo) and Exeter & Hampton Electric Company (E&H), Unitil's
New Hampshire based retail distribution utilities. The Final Plan and
related orders include a number of complex regulatory and market
restructuring issues. Among other things, the Final Plan and orders provide
for the interim recovery of CECo's and E&H's stranded costs, as defined by
the NHPUC; releases CECo and E&H from their obligation to provide electric
service and prohibits them from making energy sales after Choice Date; and
requires CECo and E&H to terminate the System Agreement under which they
currently purchase all their power supply requirements from Unitil Power
Corp. The provisions of the System Agreement permit termination by any
party thereto on seven years prior written notice. The NHPUC Final Plan and
orders establish a novel standard relative to stranded cost recovery. Under
the Final Plan the NHPUC bases recovery on an electric utility's stranded
cost, at least during the interim recovery period, on a utility's performance
in maintaining rates at or below the regional average rate. CECo's and E&H's
rates are currently among the lowest in the region and below the regional
average. As a result, under this methodology, CECo and E&H are currently
permitted to collect 100% of their stranded costs, as defined by the NHPUC.
The NHPUC Final Plan and orders raised a number of issues on which
Unitil will seek rehearing and clarification. These issues include whether
Unitil's unregulated affiliates will be allowed to sell competitive services
and use the Unitil name in the existing service territories; the methodology
for the recovery of all of CECo's and E&H's above-market power supply
obligations incurred under the System Agreement by Unitil Power through
retail rates; and the limitations of the NHPUC's authority over transmission
tariffs and wholesale arrangements which are in the exclusive jurisdiction
of the FERC, including the recovery of FERC approved wholesale charges
through retail rates.
Unitil is unable to predict at this time what the NHPUC's response
will be to its request for rehearing and clarification or what the ultimate
impact of these decisions may be. Until is pursuing the necessary
administrative appeal and court actions to ensure full recovery of
commitments and obligations incurred to serve customers in the Company's New
Hampshire franchises, and to permit Unitil to freely pursue new opportunities
in the competitive energy market.
On March 3, 1997, Northeast Utilities, the parent company of the
largest investor owned utility in New Hampshire, filed a suit in United
States District Court in Concord, New Hampshire, to enjoin implementation of
the Final Plan. On March 17, 1997, Unitil moved to intervene in the
proceeding on common issues of law, including whether the NHPUC is preempted
under federal law from denying full recovery of FERC- approved wholesale
costs in retail rates. At this time the Company is unable to predict the
ultimate impact that the Final Plan and related orders will have on the
Company, or the likely result of the Northeast Utilities lawsuit.
NH Pilot Program --- In June 1996, the New Hampshire Retail Competition
Pilot Program (Pilot Program), mandated by legislation enacted a year
earlier, became operational. During the two-year term of the Pilot Program,
up to 3% or some 17,000 electric consumers are allowed to choose from
competing electric suppliers, and have this supply delivered across the
local utility system. More than thirty electric suppliers, including Unitil
Resources, are currently authorized to market electricity to Pilot Program
participants. Unitil Resources began competitive marketing efforts in May,
and began making sales in June.
Under the Pilot Program, the NHPUC initially ordered CECo and E&H to
file tariffs which included a 10% discount to encourage participation and a
mechanism to protect non participants from any adverse cost consequences
resulting from changes in power supply obligations. Both these tariff items
would have had a significant impact on the ability of the Company to recover
its power supply obligations. However, after filing for reconsideration of
the NHPUC's Order, the Company entered into a settlement agreement with the
NHPUC staff and the Office of the Consumer Advocate which provides the
Company an opportunity to mitigate any losses which may result under the
Pilot Program. The settlement was approved by the NHPUC on July 1, 1996. The
Company also recorded in 1996, a one-time charge to earnings for estimated
losses relating to Pilot Program operations.
Massachusetts --- In March 1996, the MDPU issued a Notice of Inquiry/
Rulemaking, opening a new phase in its investigation on the restructuring of
the electric utility industry in Massachusetts. Throughout 1996 the MDPU
conducted a comprehensive information gathering effort, including holding
numerous legislative style public hearings. On December 30, 1996, the MDPU
issued a document entitled Electric Utility Restructuring Plan: Model Rules
and Legislative Proposal. In this document the MDPU presented its proposed
framework, model rules and proposed legislation for a restructured electric
utility industry. On February 24, 1997, the Governor of Massachusetts filed
legislation for electric industry restructuring which was generally
consistent with the MDPU's proposal.
The MDPU's proposed rules provide transition measures to accomplish
the change from a regulated industry to a competitive market, as early as
January 1, 1998. These measures include consumer safety and reliability
standards, environmental protection measures and a reasonable framework for
the recovery of utilities' stranded costs related to prudent generation
investments and purchased power obligations. Included in the proposed rules
and regulations is the requirement that each electric utility file
"unbundled rates," that is, separate rate components for distribution,
transmission and generation services and for access to the competitive
supplier market. The MDPU has identified the unbundling of rates as
"critical to provide both customers and competitors with the information
they need to make decisions in a more competitive environment." The MDPU
has required that the unbundled rates be revenue neutral for the Company,
for each rate class, and for each customer. The Company filed its unbundled
rates on March 3, 1997 to become effective on or after July 1, 1997, after
approval by the MDPU.
The MDPU has been supportive of the settlement process as a way to
expedite electric utility restructuring in Massachusetts. On February 26,
1997, the MDPU approved a restructuring plan filed by the New England
Electric System, Massachusetts Attorney General (Mass AG), the Massachusetts
Division of Energy Resources and numerous other parties. Under this
settlement, consumers will be allowed to choose an electricity supplier as
early as January 1, 1998, and will receive a 10% reduction on their electric
bills. The settlement requires the utility to divest all its generation
plant, and provides the utility with the opportunity to fully recover all of
its stranded costs. Several other settlement agreements have been reached in
principal with the Mass AG and other Massachusetts electric utilities. The
Company is currently developing a transition plan for its Massachusetts
utility subsidiary and exploring the use of the settlement process to
expedite its restructuring process.
Each of the settlements reached are subject to restructuring
legislation that may be enacted by the Massachusetts Legislature. On March
20, 1997, the Special Joint Committee on Electric Industry Restructuring of
the Massachusetts Legislature issued a lengthy report and proposed
legislation recommending retail competition and the recovery of prudently
incurred generation cost for a period of ten years. The Committee also
recommended that in order to be allowed to recover stranded cost that
companies had to provide for a ten percent (10%) reduction in customer bills.
FG&E cannot predict what legislation, if any, will be adopted by the
legislature and whether that legislation will allow for full recovery of
stranded costs. Fitchburg does believe it is legally entitled to such
recovery and will take appropriate actions to provide for such recovery.
Gas Utility Industry Restructuring and Competition
Unitil's retail distribution gas operations have historically been
subject to competition from fuel oil suppliers, electric utilities and
propane suppliers, and other fuel providers for heating, water heating,
cooking, industrial processes and other purposes. However, over the past
several years changes in both federal and state regulation of the natural
gas industry have resulted in increased "gas on gas" competition for the
retail sale of natural gas.
In April, 1992 the FERC issued Order 636 (Order 636), which
substantially revised the regulation of interstate pipelines. Order 636
mandated, among other things, the unbundling of interstate pipeline sales
and transportation services and required pipelines to provide open-access
transportation on an equal basis for all gas supplies. This unbundling of
services at the interstate pipeline level has changed the historical
relationships of the natural gas industry, whereby producers sold to
pipelines, pipelines sold to local gas distribution companies, such as FG&E,
and local distribution companies to end-use customers. Now local gas
distribution companies or end-use customers may directly utilize pipeline
services for purchases, or simply for the transportation of gas purchased
from third parties.
During 1996, the MDPU ordered all Massachusetts gas distribution
utilities to offer "unbundled" gas services to interruptible and special
contract customers, as a means of promoting greater retail sales competition.
Unbundled service separates the supply and transportation of gas to the
city-gate (i.e. the point where the local distribution utility takes gas
from the interstate pipeline into its distribution system ) from the
delivery of that gas to the customers facility through that distribution
system.
While Unitil's retail gas distribution operations have been, and
continue to be, subject to competition from electricity, oil, propane, coal
and other fuels, federal and state regulatory changes have created the
potential for increased competition among existing and new suppliers or
natural gas marketers for retail gas sales. In particular, gas marketers
can be expected to seek to provide sales services to end-use customers
within FG&E's retail service territory. The Company expects that any third-
party sales that are made within its gas service territory, will continue to
be delivered over FG&E's local distribution system to customers. Because
the company earns its margin on its gas distribution services and not on gas
sales, the level of margins for distribution services provided to third
parties is currently the same to the Company as if it sold the gas supplies
directly to the same end-users. Similar opportunities may exist for the
Company to market gas to new or existing retail customers, whether or not
located within FG&E's franchise territory. Several gas distribution
companies in Massachusetts have proposed that they be allowed to exit the
business of the regulated sales of gas to retail customers and remain
responsible only for the delivery of gas over their distribution system.
These proposals are similar to restructuring proposals on the electric side
of the business in that customers will be allowed to choose there own gas
supplier. Unitil believes that these proposals, if adopted by the MDPU,
will not have a material adverse effect on the Company's gas operations.
Electric Power Supply
New England Power Pool --- CECo, E&H, FG&E and Unitil Power are electric
utility members of the New England Power Pool (NEPOOL). In addition, Unitil
Resources also became a member of NEPOOL on March 1, 1997. NEPOOL was formed
to assure reliable operation of the bulk power system in the most economic
manner for the region. Under the NEPOOL Agreement, to which virtually all
New England electric utilities are parties, substantially all operation and
dispatching of electric generation and bulk transmission capacity in New
England is performed on a regional basis. NEPOOL is governed by an agreement
that is filed with the FERC and its provisions are subject to continuing FERC
jurisdiction. The NEPOOL Agreement imposes generating capacity and reserve
obligations, provides for the use of major transmission facilities and
payments associated therewith. The most notable benefits of NEPOOL are
coordinated power system operation in a reliable manner and providing a
supportive business environment for the development of a competitive electric
marketplace.
As a result of ongoing legislative and regulatory initiatives which
are primarily focused on the deregulation of the generation and supply of
electricity and the corresponding development of a competitive market place
from which customers could choose their electric energy supplier, the NEPOOL
Agreement is being restructured. NEPOOL's membership provisions have been
broadened to cover all entities engaged in the electricity business in New
England, including power marketers and brokers, independent power producers
and load aggregators. Operation of the regional bulk power system will be
provided by a new independent corporate entity, so that there will be no
opportunity for conflicting financial interests between the system operator
and the market-driven participants. Various energy and capacity products
will be traded in open, competitive markets, with transmission access and
pricing subject to a regional tariff designed to promote competition among
power suppliers. The proposed restructuring changes have been filed with FERC
as an amendment to the NEPOOL Agreement, and the resulting FERC proceedings
are expected to take place in stages during 1997.
Energy Resources --- Each electric utility's capability responsibility under
the current NEPOOL Agreement involves carrying an allocated share of New
England capacity requirements which is determined for each six-month period
based on regional reliability criteria. Unitil Power, as the full
requirements supplier to CECo and E&H, had a capability responsibility as of
December, 1996 of 231.34 MW and a corresponding peak demand of 189.14 MW
that occurred on August 8, 1996. FG&E's capability responsibility as of
December, 1996 was 93.77 MW, with a corresponding peak demand of 79.69 MW
that occurred on June 12, 1996.
To meet the needs of CECo and E&H, Unitil Power has contracted for
generating capacity and energy and for associated transmission services as
needed to meet NEPOOL requirements and to provide a diverse and economical
energy supply. Unitil Power's purchases are from various utility and non-
utility generating units using a variety of fuels and from several utility
systems in the U.S. and Canada. For the twelve months ending December 31,
1996, Unitil Power's energy needs were provided by the following fuel
sources: nuclear (30%), oil (20%), coal (14%), gas (18%), wood and refuse
(4%) , hydro (1%), and system and other (13%).
FG&E meets its capacity requirements through purchase power contracts
and ownership interests in three generating units in which FG&E participates
on a tenancy-in-common basis as a nonoperating owner. FG&E's purchases are
from various utility and non-utility generating units using a variety of
fuels and from several utility systems in the U.S. and Canada. For the
twelve months ending December 31, 1996, FG&E's energy needs, including
generation from joint-owned units, were provided from the following fuel
sources: nuclear (18%), oil (19%), wood (26%), hydro (3%), coal (10%) and
gas, system and other (24%).
FG&E has a 4.5% ownership interest, or 20.12 MW, in an oil and
natural gas-fired generating plant in New Haven, Connecticut, which is
operated by The United Illuminating Company, the plant's majority owner. FG&E
also has a 0.1822% ownership interest, or 1.13 MW, in an oil-fired generating
plant in Yarmouth, Maine, which is operated by Central Maine Power Company as
the majority owner, and a 0.217% ownership interest, or 2.5 MW, in the
Millstone 3 nuclear unit operated by Northeast Utilities, parent of the
principal owners of that unit. In addition, FG&E operates an oil-fired
combustion turbine with a current capability of 26.6 MW under a long-term
financing lease.
Fuel --- Oil: Approximately 19% of FG&E's and 20% of Unitil Power's
electric power in 1996 was provided by oil-fired units, some of which are
owned by FG&E. Most fuel oil used by New England electric utilities is
acquired from foreign sources and is subject to interruption and price
increases by foreign governments.
Coal: Approximately 10% of FG&E's and 14% of Unitil Power's 1996
requirements were from coal-burning facilities. The facilities generally
purchase their coal under long term supply agreements with prices tied to
economic indices. Although coal is stored both on-site and by fuel suppliers,
long term interruptions of coal supply may result in limitations in the
production of power or fuel switching to oil and thus result in higher
energy prices.
Nuclear: FG&E has a 0.217% ownership interest in Millstone Unit No. 3
(the Unit). The Unit has contracted for certain segments of the nuclear fuel
production cycle through various dates. This cycle includes, among other
things, mining, enrichment and disposal of used fuel. Contracts for various
segments of the fuel cycle will be required in the future, and their
availability, prices and terms cannot now be predicted.
Pursuant to the Nuclear Waste Policy Act of 1982, the participants
in Millstone 3 were required to enter into contracts with the United States
Department of Energy, prior to the operation of that Unit, for the transport
and disposal of spent fuel at a nuclear waste repository. Under the Act, a
national repository for nuclear waste was anticipated to be in operation by
1998. FG&E cannot predict whether the Federal government will be able to
provide interim storage or permanent disposal repositories for spent fuel.
Gas Supply
FG&E distributes gas purchased from domestic and Canadian suppliers
under long term contracts as well as gas purchased from producers and
marketers on the spot market. The following tables summarize actual gas
purchases by source of supply and the cost of gas sold for the years 1994
through 1996.
Sources of Gas Supply
(Expressed as percent of total MMBtu of gas purchased)
Natural Gas: 1996 1995 1994
Domestic firm.................................. 80.8% 82.3% 81.9%
Canadian firm.................................. 7.0% 5.6% 6.2%
Domestic spot market........................... 10.7% 11.1% 9.0%
Total natural gas.................................. 98.5% 99.0% 97.1%
Supplemental gas................................... 1.5% 1.0% 2.9%
Total gas purchases................................ 100.0% 100.0% 100.0%
Cost of Gas Sold
1996 1995 1994
Cost of gas purchased and sold per MMBtu.......... $3.95 $3.03 $3.47
Percent Increase (Decrease) from prior year....... 30.4% (12.7)% (8.2)%
As a supplement to pipeline natural gas, FG&E owns a propane air gas
plant and has under a financial lease a liquefied natural gas (LNG) storage
and vaporization facility. These plants are used principally during peak
load periods to augment the supply of pipeline natural gas.
Environmental Matters
The Company does not expect that compliance with environmental laws
or regulations will have a material effect on its business, or the businesses
of its subsidiaries. The Company does not know whether, or to what extent,
such regulations may affect it or its subsidiaries by impinging on the
operations of other electric and gas utilities in New England.
Unitil Power and FG&E purchase wholesale capacity and energy from a
diverse group of suppliers using various fuel sources and FG&E has ownership
interests in certain generating plants. Some of the purchase power contracts
contain cost adjustment provisions that may allow the supplier to pass
through environmental remediation costs. The Company has not been informed
whether any of these suppliers are likely to incur significant environmental
remediation costs and, if so, which if any such costs may be passed through.
The Company continues to work with federal and state environmental
agencies to identify and assess environmental issues at two former gas
manufacturing sites, the Sawyer Passway ("Sawyer Passway") and Logan Street
("Logan Street") sites, operated by FG&E.
In December 1994 the Company accepted a Tier 1B permit from the
Massachusetts Department of Environmental Protection (DEP) to address the
Sawyer Passway site in Fitchburg, Massachusetts pursuant to the requirements
of the Massachusetts Contingency Plan. A supplemental Phase II field
investigation was conducted at the Site in July and August of 1996. Results
of the investigation confirm, in the Phase II Investigation Report (the
"Report"), the presence of some contamination, however, the Report indicates
the identified contamination does not present "an imminent hazard to health,
safety or the environment." The Phase II Investigation Report and the Risk
Characterization was submitted to the DEP on January 31, 1997. Phase III,
the Identification and Selection of Comprehensive Remedial Action
Alternatives, has been delayed until June 30, 1997 to permit investigation
of redevelopment alternatives on this site.
The Company also conducted a Phase I assessment of the Logan Street
Site on April 12, 1995. Results of that investigation suggest that there is
some evidence of both groundwater and soil contamination. The site was
numerically ranked using the Massachusetts Contingency Plan Numerical Ranking
System Scoresheet and was classified as a Tier II Site. Currently, site
closeout options are being investigated.
The costs of such assessments and any remedial action determined to
be necessary will initially be funded from traditional sources of capital and
recovered from customers under a rate recovery mechanism approved by the
Massachuestts Department of Public Utilities. The Company also has a number
of liability insurance policies that may provide coverage for environmental
remediation at this site. Because these investigations are at an early stage
management cannot, at this time, predict the costs of future analysis and
remediation.
Capital Requirements
Net capital expenditures increased approximately $5.8 million in 1996
compared to 1995, reflecting a $1.6 million increase in planned spending for
utility system improvements as well as $2.7 million increase in expenditures
for the construction of the Company's new corporate headquarters. The Company
also received cash payments of $875,000 and $2 million from the State of New
Hampshire in 1996 and 1995, respectively, related to the eminent domain
taking of is former corporate headquarters for a highway expansion project.
In 1997, total capital expenditures are expected to approximate $13.3
million. This projection reflects normal capital expenditures for system
expansions, replacements and other improvements.
Financing Activities
The change in Cash Flows from Financing Activities in 1996 compared
to 1995 reflects an increase in short-term borrowing requirements. Higher
short-term borrowings in 1996 were primarily due to funding of the timing
difference between payments on fuel, purchased power and purchased gas costs
and the corresponding recovery of these costs in revenue billed under
periodic cost recovery mechanisms as well as the interim construction
financing of the Company's new corporate headquarters.
No long-term debt was issued by any of the Unitil System companies
during 1996 or 1995. The Company anticipates that it will complete a
permanent long-term financing of its headquarters building in the first half
of 1997.
The Company currently has unsecured committed bank lines for short-
term debt aggregating $23,000,000 with four banks for which it pays
commitment fees. At December 31, 1996, the unused portion of the committed
credit lines outstanding was $1,600,000. The average interest rate on all
short-term borrowings outstanding during 1996 was 5.79%.
Employees
As of December 31, 1996, the Company and its subsidiaries had 326
full-time employees. The Company considers its relationship with its
employees to be good and has not experienced any major labor disruptions
since the early 1960's.
There are 118 employees represented by labor unions. In 1995, E&H
reached a new three year pact with its employees covered by a collective
bargaining agreement. In 1994, both CECo and FG&E reached new three year
pacts with their respective employees covered by collective bargaining
agreements. The agreements provide for discreet salary adjustments,
established work practices and provided uniform benefit packages. The
current FG&E collective bargaining agreement will expire effective April 30,
1997. The current CECo collective bargaining agreement will expire effective
May 31, 1997. The Company expects to successfully negotiate new agreements
prior to the expiration dates of these contracts.
The Company and its subsidiaries, where applicable, have in effect
funded Retirement Plans and related Trust Agreements providing retirement
annuities for participating employees at age 65. The Company's policy is to
fund the pension cost accrued (see Note 9 of Notes to Consolidated Financial
Statements contained in Part II, Item 8).
Executive Officers of the Registrant
The names, ages and positions of all of the executive officers of the
Company as of March 1, 1997 are listed below, along with a brief account of
their business experience during the past five years. All officers are
elected annually by the Board of Directors at the Directors' first meeting
following the annual meeting which is held on the third Thursday in April,
or at a special meeting held in lieu thereof. There are no family
relationships among these officers, nor is there any arrangement or
understanding between any officer and any other person pursuant to which the
officer was selected. Officers of the Company also hold various Director and
Officer positions with subsidiary companies.
Name, Age Business Experience
and Position During Past 5 years
Peter J. Stulgis, 46, Mr. Stulgis has been a Director of
Chairman of the Board of Directors the Company since its incorporation
and Chief Executive Officer in 1984, and Chairman of the Board
and Chief Executive Officer since
1992. From 1987 - 1992, Mr.
Stulgis was Executive Vice President
and Chief Financial Officer of the
Company.
Michael J. Dalton, 56, Mr. Dalton has been a Director,
President and Chief Operating Officer President and Chief Operating Officer
of the Company since its incorporation
in 1984.
Gail A. Siart, 38, Ms. Siart was promoted to Chief
Chief Financial Officer, Financial Officer in 1994. Ms. Siart
Secretary and Treasurer has been Secretary of the Company
since 1988 and Treasurer since 1992.
Prior to being elected Treasurer in
1992, Ms. Siart was the System's
Subsidiary Treasurer since 1988.
James G. Daly, 39 Mr. Daly was promoted to Senior
Senior Vice President Vice President of Unitil Service
Energy Resources in 1994. Mr. Daly was Vice
Unitil Service President of Unitil Service from
1992 to 1994, and Asst. Vice
President of Unitil Service from
1988 to 1992.
George R. Gantz, 45 Mr. Gantz was promoted to Senior
Senior Vice President Vice President of Unitil Service
Business Development in 1994. Mr. Gantz was Vice
Unitil Service President of Unitil Service from
1989 to 1994, and Asst. Vice
President of Unitil Service from
1986 to 1989.
Item 2. Properties
CECo's distribution service center building and adjoining
administration building, totaling 37,560 square feet of office, warehouse
and garage area, are located on land in the City of Concord owned by CECo in
fee. CECo's sixteen electric distribution substations constitute 110,100 KVA
of capacity for the transformation of electric energy from the 34.5 KV
transmission voltage to primary distribution voltage levels. The electric
substations are, with one exception, located on land owned by CECo in fee.
The sole exception is located on land occupied pursuant to a perpetual
easement.
CECo has in excess of 39 pole miles of 34.5 KV electric transmission
facilities located, with minor exceptions, either on land owned by CECo in
fee or on land occupied pursuant to perpetual easements. CECo also has 617
pole miles of overhead electric distribution primary voltage lines and
approximately 110 cable miles of underground primary voltage lines. The
electric distribution lines are located in, on or under public highways or
private lands pursuant to lease, easement, permit, municipal consent, tariff
conditions, agreement or license, expressed or implied through use by CECo
without objection by the owners. In the case of certain distribution lines,
CECo owns only a part interest in the poles upon which its wires are
installed, the remaining interest being owned by telephone and telegraph
companies.
Additionally, CECo owns in fee 137.7 acres of land located on the
east bank of the Merrimack River in the City of Concord. Of the total
acreage, 81.2 acres are located within an industrial park zone, as specified
in the zoning ordinances of the City of Concord.
The physical properties of CECo (with certain exceptions) and its
franchises are subject to the lien of its Indenture of Mortgage and Deed of
Trust, as supplemented, under which the respective series of First Mortgage
Bonds of CECo are outstanding.
E&H's distribution and engineering service center building is located
on land owned by E&H in fee. E&H's fourteen electric distribution substations,
together with a 5,000 KVA mobile substation, constitute 91,400 KVA of
capacity for the transformation of electric energy from the 34.5 KV
transmission voltage to primary distribution voltage levels. The electric
substations are located on land owned by E&H in fee.
E&H has in excess of 68 pole miles of 34.5 KV electric transmission
facilities located on land either owned or occupied pursuant to perpetual
easements. E&H also has 693 pole miles of overhead electric distribution
primary voltage lines and approximately 77 cable miles of underground primary
voltage lines. The electric distribution lines are located in, on or under
public highways or private lands pursuant to lease, easement, permit,
municipal consent, tariff conditions, agreement or license, expressed or
implied through use by E&H without objection by the owners. In the case of
certain distribution lines, E&H owns only a part interest in the poles upon
which its wires are installed, the remaining interest being owned by
telephone and telegraph companies.
Certain physical properties of E&H and its franchises are subject to
the lien of its Indenture of Mortgage and Deed of Trust, as supplemented,
under which the respective series of First Mortgage Bonds of E&H are
outstanding.
FG&E owns a propane gas plant and leases an LNG plant, both of which
are located on land owned by it in fee. The Company has entered into
agreements for joint ownership with others of one nuclear and two fossil
fuel generating facilities. At December 31, 1996, the electric properties of
the Company consisted principally of 69 miles of transmission lines, 16
transmission and distribution substations with a total capacity of 499,160
KVA and 667 miles of distribution lines. Electric transmission facilities
(including substations) and steel, cast iron and plastic gas mains owned by
the Company are, with minor exceptions, located on land owned by the Company
in fee or occupied pursuant to perpetual easements. The Company leases its
service building, and its combustion turbine electric peaking generator and
LNG facility. (See Business - Electric Operations and Energy Supply and Gas
Operations and Supply above for additional information regarding the
Company's plants, facilities and gas mains and services.)
Unitil Realty owns the Company's new corporate headquarters building
and 12 acres of land in fee, which is located in the Town of Hampton, New
Hampshire. This facility was completed and occupied by the Company during
the summer of 1996. The Company believes that its facilities are currently
adequate for their intended uses.
Unitil Realty was, until February 13, 1995, the owner of the
Company's corporate headquarters and 36 acres of related land located in the
Town of Exeter, New Hampshire. On that date, the State of New Hampshire (the
"State") took title to and possession of the land and building through
eminent domain. The building is to be demolished in connection with the
State's Route 101 highway expansion. (See Capital Requirements under Item 1.
of this Report). The State of New Hampshire rented this facility back to
the Company, until the Company completed the construction of its new
corporate headquarters building.
Item 3. Legal Proceedings
The Company is involved in other legal and administrative proceedings
and claims of various types which arise in the ordinary course of business.
In the opinion of the Company's management, based upon information furnished
by counsel and others, the ultimate resolution of these claims will not have
a material impact on the Company's financial position.
Item 4. Submission of Matters to a Vote of Security Holders
None
PART II
Item 5. Market For Registrant's Common Equity and Related Stockholder
Matters
Common Stock Data
Dividends Paid Per Common Share 1996 1995
1st Quarter $0.33 $0.32
2nd Quarter 0.33 0.32
3rd Quarter 0.33 0.32
4th Quarter 0.33 0.32
The Year $1.32 $1.28
1996 1995
High/Ask Low/Bid High/Ask Low/Bid
1st Quarter 24 3/4 20 3/4 17 5/8 16
2nd Quarter 24 1/4 21 1/8 17 5/8 16 1/8
3rd Quarter 23 20 3/8 20 1/8 16 5/8
4th Quarter 21 1/2 18 1/4 21 3/8 19 1/8
ITEM 6. SELECTED FINANCIAL DATA
1996 1995 1994 1993 1992
Consolidated Statements of Earnings (000's)
Operating Income $14,273 $14,225 $13,754 $14,073 $13,342
Non-operating Expenses 627 (217) (64) 50 22
Income Before Interest Expense 14,900 14,008 13,690 14,123 13,364
Interest Expense, Net 6,171 5,639 5,652 6,523 6,948
Expenses (Net of Taxes) ---- ---- ---- ---- (155)
Net Income 8,729 8,369 8,038 7,600 6,571
Dividends on Preferred Stock 278 284 291 298 352
Net Income Applicable to
Common Stock $8,451 $8,085 $7,747 $7,302 $6,219
Balance Sheet Data (000's)
Utility Plant (original cost) $207,544 $190,177 $178,777 $171,540 $165,880
Total Assets 232,108 211,702 204,521 201,509 172,348
Capitalization and Short-term Debt:
Common Stock Equity 67,974 63,895 59,997 56,234 52,608
Preferred Stock 3,891 3,999 4,094 4,198 4,277
Long-Term Debt 62,211 63,505 65,580 57,378 62,041
Total Capitalization 134,076 131,399 129,671 117,810 118,926
Capitalization Ratios:
Common Stock Equity 51% 49% 46% 48% 44%
Preferred Stock 3% 3% 3% 3% 4%
Long-Term & Short-Term Debt 46% 48% 51% 49% 52%
Common Stock Data (000's)
Shares of Common Stock (Year-End) 4,384 4,330 4,268 4,205 4,152
Shares of Common Stock (Average) 4,354 4,299 4,234 4,181 4,133
Per Share Data
Earnings Per Average Share $1.94 $1.88 $1.83 $1.75 $1.50
Dividends Paid Per Share $1.32 $1.28 $1.24 $1.15 $1.10
Book Value Per Share $15.50 $14.76 $14.06 $13.37 $12.67
Electric and Gas Statistics
Electric Sales - (MWH) 1,523,788 1,401,292 1,358,165 1,303,326 1,260,747
Customers Served - Year End 89,865 88,316 86,782 85,383 85,131
Gas Sales - (000's of Therms) 24,508 22,303 23,057 22,763 23,281
Customers Served - Year End 14,848 14,846 15,012 15,340 15,514
Note: The above data have been combined and restated to reflect the merger of
FG&E into the Unitil System and the two-for-one stock split that occurred in
1992.
Item 7. Management's Discussion and Analysis of Financial Condition and Results
of Operations
Earnings and Dividends
Earnings were $1.94 per average common share outstanding for the year ending
December 31, 1996, an increase over 1995 and 1994 earnings per share of $1.88
and $1.83, respectively. 1996 marked the fourth consecutive year that Unitil
achieved record earnings. The average return on common equity in 1996 was 12.8%.
This earnings performance reflects an increase of 9% in Unitils electric and
firm natural gas sales base as well as higher operating expenses in support of
the Companys utility operations, regulatory activities and new energy related
business initiatives, and a reduction in energy consulting related revenue in
1996 compared to 1995.
Also impacting 1996 earnings were two nonrecurring and offsetting items:
1) a one-time charge related to the implementation in New Hampshire of a state
- -mandated retail pilot program on competitive energy sales, and 2) income
related to a lump sum settlement payment received in the eminent domain taking
of the Companys former corporate headquarters for a highway expansion project.
Unitils common stock dividends in 1996 were $1.32 per share, an increase of
3.1% over 1995s annual dividend of $1.28 per share. This annual dividend of
$1.32 in 1996 resulted in a payout ratio of 68%. At its January 1997 meeting,
the Unitil Board of Directors increased the quarterly dividend rate by an
additional 1.5%, resulting in the current effective annualized dividend of
$1.34 per share.
Year in Review
The Unitil Systems total electric kilowatt-hour sales increased by 8.7% in
1996 compared to 1995. Electricity sales were higher for all major customer
classes.
Electric energy sales to large industrial and commercial customers were up
substantially in 1996, as kilowatt-hour usage by this group increased 21%.
A significant factor in this growth was the addition of major new customer
loads under Unitils new competitive pricing initiatives, including the Energy
Bank TM market pricing program. Energy BankTM introduced nationally competitive
electricity prices to the New England region and was designed to attract new
large commercial and industrial customers. In 1996 electricity sales were also
higher to Unitils underlying customer sales base. Excluding sales made under
special market-based pricing programs, electricity sales to the Systems largest
commercial and industrial customers in 1996 increased 7.1%, followed by an
increase of 3.5% in sales to residential customers.
Approximately one half of the increase in sales reflects the addition of a
major new customer early in 1996 under a special competitive market pricing
arrangement. In the fall of 1996, this customer curtailed its operations to
make alterations and improvements to its facility, and has informed the Company
that it does not expect to complete this work until mid-1997.
The following table details total kilowatt-hour sales in each of the last
three years by major customer class:
KWH SALES (000s)
1996 1995 1995
Residential 524,810 507,233 507,071
Commercial 382,647 381,292 374,769
Large Commercial/Industrial 604,696 500,945 464,357
Other Sales 11,634 11,822 11,968
Total KWH Sales 1,523,788 1,401,292 1,358,165
Unitils natural gas revenue comprises approximately 12% of the Systems
total energy revenues. Firm therm sales were higher to all major customer
classes in 1996. The following table details total firm therm sales in each
of the last three years by major customer class:
FIRM THERM SALES (000s)
1996 1995 1994
Residential 13,835 12,523 13,345
Commercial 6,728 6,208 5,892
Industrial 3,945 3,572 3,820
Total Therm Sales 24,508 22,303 23,057
Total firm therm sales increased 9.9%, led by a 10.6% increase in gas sales
to industrial customers and a 10.5% increase in firm therm sales to residential
customers. This increase in gas sales was attributable to continued growth in
the local and regional economy and the beneficial impact of weather conditions
for gas sales relative to the prior year. The 1996 winter heating season in
the first quarter of the year was 11% colder, as measured in heating degree
days, compared to the extremely mild heating season in 1995.
The System's operating costs (not including fuel, purchased power and
conservation program costs, which are normally recovered from customers through
periodic cost recovery adjustment mechanisms) increased approximately $1.2
million, or 6.4% in 1996 versus 1995. This increase reflects the impact of
higher costs resulting from industry restructuring proceedings, development
and marketing of new product offerings and expenditures on improvements to
operating and customer service capabilities.
OPERATING REVENUES
The following table compares the major components of Operating Revenues for
1996, 1995 and 1994:
OPERATING REVENUE ($000s)
1996 1995 1994
Base Electric Revenue $48,588 $45,458 $44,381
Fuel & Purchased Power 100,007 90,558 88,103
Conservation Program Costs 1,101 2,083 1,613
Total Electric Revenue 149,696 138,099 134,097
Base Gas Revenue 7,676 7,105 7,348
Cost of Gas 10,439 8,202 9,935
Interruptible Revenue 2,990 2,323 1,412
Total Gas Revenue 21,105 17,630 18,695
Other Revenue 45 941 624
Total Operating Revenue $170,846 $156,670 $153,416
Electric Operating Revenue increased by $11.6 million, or 8%, in 1996
compared to 1995. Total electric operating revenue is comprised of electric
base revenue, fuel and purchased power revenue and conservation and load
management program revenue. Fuel and purchased power revenue are collected
from customers through the operation of periodic cost recovery adjustment
mechanisms. Changes in this component of operating revenue do not affect net
income as they normally mirror corresponding changes in fuel and purchased
power costs. Conservation and load management program revenue is also
collected from customers through periodic cost recovery mechanisms, reflecting
underlying changes in conservation and load management program costs. Electric
base revenue is that portion of electric operating revenue that has a direct
impact on net income. In 1996, electric base revenue rose by approximately
$2.7 million. This 6.1% increase in electric base revenue was due to the growth
in the Systems total kilowatt-hour sales and kilowatt billing demands of 8.7%
and 9.4%, respectively.
In 1995, the System's electric operating revenue increased by approxi-
mately $4.0 million, or 3% with the electric base revenue portion increasing
by approximately 2.5%. This increase in electric base revenue in 1995,
compared to 1994, was due to the growth in the System's total electric
kilowatt-hour sales and kilowatt billing demands of 3.2% and 4.4%,
respectively.
Gas Operating Revenue increased by $3.5 million, or 19.7%, in 1996
compared to 1995. Gas operating revenue is comprised of three components:
cost of gas revenue, interruptible revenue and gas base revenue. Cost of gas
revenue is collected from customers through the operation of a cost of gas
adjustment mechanism. Changes in this component of gas operating revenue does
not affect net income as it reflects corresponding changes in gas supply costs.
Interruptible revenue increased by $700,000, an increase of almost 29%
in 1996, due to competitive prices of natural gas relative to oil throughout
most of 1996. Margins earned on interruptible gas sales are used to directly
lower rates to firm customers through the cost of gas adjustment mechanism and
do not directly impact the Company's net income. Gas base revenue is that
portion of gas operating revenue that has a direct impact on net income. In
1996, gas base revenue increased $577,000, on an overall increase of 9.9% in
firm therm sales, due to improving economic conditions and a colder-than-
normal heating season in 1996 as compared to the extremely mild heating
season in 1995.
In 1995, total gas operating revenue decreased by about $1.1 million,
or 5.7%, as compared to 1994. Interruptible revenue increased more than 64%,
due to very favorable spot market prices for gas in 1995. Gas base revenue
decreased in 1995 due to a 3.3% reduction in therm sales to firm customers
which primarily reflected the extremely mild heating season in 1995.
Other Revenue declined from $940,000 in 1995 to $45,000 in 1996. The
primary factor for this decline was the termination of a service agreement at
the end of 1995 between Unitil Resources and one of its principal customers
to which it provided administrative, management and power brokering services.
OPERATING EXPENSES
Fuel and Purchased Power reflects the cost of fuel used in electric
generation and wholesale energy and capacity purchased to meet the Unitil
System's electric energy requirements. Fuel and purchased power expenses
(normally recoverable from customers through periodic cost recovery adjustment
mechanisms) increased $8.4 million, or 9.1% in 1996 compared to 1995.
The change reflects an increase in the System's total energy requirements in
1996, coupled with higher fossil fuel costs. The combined resource portfolio
of the Unitil System is comprised of a variety of power supply sources,
including owned generation, utility purchase power contracts and purchases
from non-utility generators. The Unitil System's total energy supply resources
for 1996 were comprised of: 17% from subsidiary-owned generation; 63% from
various utility-purchased power contracts; and 20% representing purchases
from non-utility generation units.
In 1995 compared to 1994, fuel and purchase power expenses increased
$2.0 million, or 2.2%.
Purchased Gas reflects gas purchased and made to supply the System's total
gas energy requirements. Purchased Gas is normally recoverable from customers
through the cost of gas adjustment mechanism. Purchased Gas costs increased
by approximately $2.8 million or 26.6% in 1996 as compared to 1995, reflecting
the higher cost of gas available in the marketplace and an increase in therms
purchased.
Purchased Gas decreased by $617,000, or 5.5% in 1995 as compared to
1994, based on a lower cost of gas, partially offset by an increase in therms
purchased for interruptible sales.
Under Order 636, the Federal Energy Regulatory Commission (FERC) has
allowed gas pipeline suppliers to recover prudently incurred costs resulting
from the transition into a deregulated environment. The Company's combination
gas & electric utility operating subsidiary, has been incurring FERC-approved
transition charges from its natural gas pipeline supplier since 1992. Through
the end of 1996, the amount of transition costs incurred by the Company totaled
approximately $2.7 million. These costs are being recovered directly from gas
customers through the cost of gas adjustment mechanism. On the basis of
estimates included in rate filings before the FERC and other publicly available
information, the Company currently estimates that it may incur up to an
additional $700,000 of transition costs in future years. The Company expects
full recovery of these costs through billings to customers.
Operation and Maintenance expense, which include conservation and load
management (C&LM) program and purchase power related expenditures, increased
by approximately $1.3 million, or 5.6% in 1996 compared to 1995. The increase
primarily reflects higher operating expenses in support of the companies utility
operations, regulatory activities and new business initiatives.
In 1995, Operation and Maintenance expense increased by approximately
$900,000, or 4.2%. This increase primarily reflected higher conservation and
load management program expenditures. In 1995, expenditures on this component
of operation and maintenance expenses was over $2.1 million -- a 30% increase
over 1994's conservation and load management program expenditure level.
Excluding these costs, the System's total operating and maintenance costs
were relatively unchanged in 1995 compared to 1994.
DEPRECIATION, AMORTIZATION AND TAXES
Depreciation expense increased more than 10% for 1996 over the prior
year due primarily to a higher level of plant in service.
Amortization of the Cost of Abandoned Properties principally relates
to the abandonment of an investment in the Seabrook Nuclear Power Plant by
the Company's Massachusetts retail operating subsidiary. A portion of the
former investment in this project is being recovered in rates to electric
customers as allowed by the Massachusetts Department of Public Utilities.
Federal and State Income Taxes increased in 1996 compared to 1995
by $478,000. This result reflects higher net income before taxes in 1996
and the absence of a nonrecurring tax benefit realized by the Company in 1995
from a donation of land to an economic development project in Fitchburg,
Massachusetts. Despite an increase in net income before taxes, Federal and
State Income Taxes remained relatively unchanged in 1995, primarily reflecting
the impact of a nonrecurring tax benefit realized by the Company from the above
mentioned land donation.
Local Property Taxes increased $155,000, or 5.1%, in 1996. This increase
mainly reflects the annual property tax increases set by local communities.
Local Property taxes increased in 1995, compared to 1994 by 13.2%.
NON-OPERATING INCOME/EXPENSES
Non-Operating Income/Expenses in 1996 represent income of approximately
$627,000, primarily reflecting the additional funds received in settlement of
an eminent domain taking by the State of New Hampshire of the Companys former
corporate headquarters for a highway expansion project, offset by other
non-operating expenses.
INTEREST EXPENSES
Interest Expense, Net increased 9.4% in 1996 over 1995, due to an
increase in short-term borrowings. This increase in short term borrowings
reflects the timing difference between required payments for fuel, purchase
power and purchase gas costs and the recovery of these cost from customers
through periodic cost recovery mechanisms. Increased short-term borrowing
in 1996 was also related to the interim construction financing of the Companys
new corporate headquarters. The company anticipates that it will complete a
permanent long-term financing of its headquarters in the first half of 1997.
Interest Expense remained relatively unchanged in 1995 compared to
1994.
CAPITAL REQUIREMENTS AND LIQUIDITY
The Unitil System requires capital for the acquisition of property,
plant and equipment in order to improve, protect, maintain and expand its
electric and gas distribution systems, to develop and market new energy related
products and to improve customer service operations and capabilities. The
capital necessary to meet these requirements is derived primarily from the
Company's retained earnings and through the System's Dividend Reinvestment
and Stock Purchase Plan. When internally-generated funds are not available,
it is the Company's policy to borrow interim funds on a short-term basis to
meet the capital requirements of its subsidiaries and, when necessary, to
repay short-term debt through the issuance of permanent financing. The
size and timing of such financings depend on developments in the securities
markets, the ability to meet certain financing covenants and the receipt of
appropriate regulatory approval. The Company attempts to maintain a conservative
capitalization structure, which contributes to both the stability of Unitil
and its ability to market new securities. The Company has been able to access
the financial markets to meet its capital requirements and does not anticipate
a change in its access to, or the availability of, capital in the coming year.
Cash Flow from Operations decreased by $10.8 million in 1996 after
increasing by $0.7 million in 1995. Over one-half of the change in cash
provided by operating activities in 1996 compared to 1995 was the result of
a $6.0 million increase in the timing difference between the payment on fuel,
purchased power and purchased gas costs and the corresponding recovery of
these costs in revenue billed under periodic cost recovery mechanisms. The
balance of the decrease reflects other changes in the Companys working capital
requirements as detailed in the Consolidated Statements of Cash Flows.
Operating Activities ($000's): 1996 1995 1994
Net Cash Provided by Operating Activities $6,229 $17,018 $16,349
Cash Flow from Investing Activities increased approximately $5.8
million in 1996 compared to 1995, reflecting a $1.6 million increase in planned
spending for utility system improvements as well as $2.7 million increase in
expenditures for the construction of the Companys new corporate headquarters.
The Company also received cash payments of $875,000 and $2 million from the
State of New Hampshire in 1996 and 1995, respectively, related to the eminent
domain taking of is former corporate headquarters for a highway expansion
project.
Investing Activities ($000's): 1996 1995 1994
Net Cash (Used in)Investing Activities ($18,484) ($12,645) ($8,943)
In 1997, total capital expenditures are expected to approximate $13.3
million. This projection reflects normal capital expenditures for system
expansions, replacements and other improvements.
The change in Cash Flows from Financing Activities in 1996 compared
to 1995 reflects an increase in short-term borrowing requirements. Higher
short-term borrowings in 1996 were primarily due to funding of the timing
difference between payments on fuel, purchased power and purchased gas costs
and the corresponding recovery of these costs in revenue billed under periodic
cost recovery mechanisms as well as the interim construction financing of the
Companys new corporate headquarters. The Company anticipates that it will
complete a permanent long-term financing of its headquarters building in the
first half of 1997. Short term borrowing requirements are met through Unitil's
short-term credit facilities with four different banks.
Financing Activities ($000's): 1996 1995 1994
Net Cash Provided by (Used In) Financing Activities $11,759 ($4,785) ($5,301)
During 1996, the Company raised $1,111,261 of additional common equity
capital through the issuance of 52,081 shares of common stock in connection
with the Dividend Reinvestment and Tax Deferred Savings and Investment plans.
The Company raised $1,009,499 of additional common equity capital in 1995 and
$1,037,809 of additional equity capital in 1994, through the respective issuance
of 58,457 and 58,229 shares of common stock in connection with these plans.
The Company also issued shares during each of the years from 1994 through 1996
as a result of the exercise of options granted under the Company's Key Employee
Stock Option Plan (KESOP). The total number of shares issued under the KESOP
plan in 1996, 1995 and 1994 were 2,400 shares, 3,291 shares and 4,110 shares,
respectively.
REGULATORY MATTERS
Competition and Restructuring - Regulatory activity in both New Hampshire and
Massachusetts has focused on the restructuring of the electric industry and
the process of deregulating the retail sale of electric energy. In both states,
January 1, 1998 has been targeted as the beginning of competition, or "Choice
Date." Under these restructuring proposals, customers would be allowed to choose
their supplier of electricity from the competitive market, and have their local
utility deliver that electricity over its distribution systems at regulated
rates.
Unitil has been preparing for this restructuring by developing
transition plans that will move its utility subsidiaries into this new market
structure in a way that will ensure fairness in the treatment of the Companys
assets and obligations that are dedicated to the current regulated franchises
and, at the same time, provide choice for all customers. Simultaneous with
this transition process for Unitils regulated utilities, the Company is moving
to position its competitive market subsidiary, Unitil Resources, Inc., to
pursue growth areas both within and beyond the Companys traditional franchises
in all energy-related sectors, including electricity, gas, oil and propane.
New Hampshire -- In New Hampshire, House Bill 1392 (HB 1392) was signed
into law by the Governor in May 1996. HB 1392 establishes principles, standards
and a timetable for the New Hampshire Public Utilities Commission (NHPUC) to
implement full, open retail electric competition as early as January 1, 1998,
but no later than July 1, 1998. The bill also directs the NHPUC to set
interim access charges for the recovery of above market "stranded" power supply
costs and to make a final determination on these access charges within two years
of implementation of full competition.
As required by HB 1392, the NHPUC has set a procedural schedule for
opening up the state to retail competition. In connection with that procedural
schedule, the Company has filed with the NHPUC its "Customer Choice" Plan a
transition plan that guarantees electric consumers open access to the retail
energy supply market in New Hampshire. Under this plan, all of the Companys
New Hampshire customers will continue to enjoy Unitils very competitive electric
rates, among the lowest in New England, and also may benefit from future market
competition and the resulting energy savings. Unitils Customer Choice Plan
guarantees all its customers competitive retail delivery prices, open and
nondiscriminatory access to competitive electricity suppliers, reliable electric
service and comprehensive consumer protection standards. The Companys Customer
Choice Plan achieves these benefits and safeguards for consumers while providing
for full recovery of Unitils obligations that are dedicated to serving customers
in the Companys New Hampshire franchises.
On February 28, 1997, the NHPUC issued its Final Plan for restructuring
the electric utility industry in New Hampshire. Concurrently, the NHPUC
issued five supplemental orders establishing interim stranded cost charges for
each of the states electric utilities, including Concord Electric Company
(CECo) and Exeter & Hampton Electric Company (E&H), Unitils New Hampshire based
electric distribution operating companies. The Final Plan and related orders
include a number of complex regulatory and market restructuring issues which
the Company is currently evaluating. Among other things, the Final Plan and
orders provide for the recovery of CECos and E&Hs stranded costs related to
their purchase power obligations and requires them to terminate the System
Agreement under which they currently purchase all their power supply
requirements from Unitil Power Corp. The termination provisions of the
System Agreement permit termination by any party thereto on seven years prior
written notice. On March 3, 1997, Northeast Utilities, the Parent Company of
Public Service Company of New Hampshire, filed a suit in United States District
Court in Concord, New Hampshire, to enjoin implementation of the Final Plan.
At this time the Company is unable to predict the ultimate impact that the
Final Plan and related orders will have on the Company, or the likely result
of the Northeast Utilities lawsuit.
In June 1996, the New Hampshire Retail Competition Pilot Program
(Pilot Program), mandated by legislation enacted a year earlier, became
operational. During the two-year term of the Pilot Program, up to 3% or some
17,000 electric consumers are allowed to choose from competing electric
suppliers, and have this supply delivered across the local utility system.
More than thirty electric suppliers, including Unitil Resources, the Companys
competitive market subsidiary, are currently authorized to market electricity
to Pilot Program participants. Unitil Resources began competitive marketing
efforts in May, and began making sales in June.
Under the Pilot Program, the NHPUC initially ordered Concord Electric
Company and Exeter & Hampton Electric Company, Unitils New Hampshire-based
distribution companies, to file tariffs which included a 10% discount to
encourage participation and a mechanism to protect nonparticipants from any
adverse cost consequences resulting from changes in power supply obligations.
Both these tariff items would have had a significant impact on the ability of
the Company to recover its power supply obligations. However, after filing for
reconsideration of the NHPUCs Order, the Company entered into a settlement
agreement with the NHPUC staff and the Office of the Consumer Advocate which
provides the Company an opportunity to mitigate any losses which may result
under the Pilot Program. The settlement was approved by the NHPUC on July 1,
1996. The Company also recorded in 1996, a one-time charge to earnings for
estimated losses relating to Pilot Program operations.
Massachusetts- In March 1996, the Massachusetts Department of Public Utilities
(MDPU) issued a Notice of Inquiry/Rulemaking, opening a new phase in its
investigation on the restructuring of the electric utility industry in
Massachusetts. Throughout 1996 the MDPU conducted a comprehensive information
gathering effort, including holding numerous legislative style public hearings.
On December 30, 1996, the MDPU issued a document entitled Electric Utility
Restructuring Plan: Model Rules and Legislative Proposal. In this document
the MDPU presented its framework, model rules and proposed legislation for
a restructured electric utility industry. On February 24, 1997, the
Massachusetts Governor filed legislation for electric industry restructuring
which is generally consistent with the MDPUs proposal.
The MDPUs proposed rules provide transition measures to accomplish
the change from a regulated industry to a competitive market, as early as
January 1, 1998. These measures include consumer safety and reliability
standards, environmental protection measures and a reasonable framework for
the recovery of utilities stranded costs related to generation investments
and purchased power obligations. Included in the proposed rules and regulations
is the requirement that each electric utility file "unbundled rates," that
is, separate rate components for distribution, transmission and generation
services and for access to the competitive supplier market. The MDPU has
identified the unbundling of rates as "critical to provide both customers
and competitors with the information they need to make decisions in a more
competitive environment." The MDPU has required that the unbundled rates be
revenue neutral for the Company, for each rate class, and for each customer.
The Company is required to submit unbundled rates by March 3, 1997 to become
effective on or after July 1, 1997.
The MDPU has been supportive of the settlement process as a way to
expedite electric utility restructuring in Massachusetts. On February 26,
1997, the MDPU approved a restructuring plan filed by the Massachusetts
Attorney General, the Massachusetts Division of Energy Resources and numerous
other parties in the context of a settlement agreement with the states
largest investor owned utility. Under this plan, consumers will be allowed
to choose an electricity suppler beginning as early as January 1, 1998, and
are guaranteed a 10% savings on their electric bills. The plan requires the
utility to divest itself of ownership of all its generation plant, and provides
the utility with the opportunity to fully recover its stranded costs. It is
likely that several restructuring offers of settlement will be filed in the
first half of 1997 by other Massachusetts electric utilities. The Company is
currently developing a transition plan for its Massachusetts utility subsidiary
and exploring the use of the settlement process to expedite the restructuring
process.
Rate Cases
The last formal regulatory hearings to increase base rates for Unitil's
three retail operating subsidiaries occurred in 1985 for Concord Electric
Company, 1984 for Fitchburg Gas and Electric Light Company and 1981 for
Exeter & Hampton Electric Company. A majority of the System's operating
revenues are collected under various periodic rate adjustment mechanisms
including fuel, purchased power, cost of gas and conservation program cost
recovery mechanisms.
Millstone Unit No. 3
Unitils Massachusetts operating subsidiary, Fitchburg Gas and Electric
Light Company (FG&E), has a 0.217% ownership in the Millstone Unit No. 3
(Millstone 3) nuclear generating unit which supplies it with 2.49 MW of
electric capacity. In January 1996 the Nuclear Regulatory Commission (NRC)
placed Millstone 3 on its watch list as a Category 2 facility, which calls
for increased NRC inspection attention. In March 1996 the NRC requested
additional information about the operation of the unit from Northeast Utilities
(NU), the units managing owner. As a result of an engineering evaluation
completed by NU, Millstone 3 was taken out of service on March 30, 1996.
The NRC later informed NU, in a letter dated June 28, 1996, that it had
reclassified Millstone 3 as a Category 3 facility. The NRC assigns this rating
to plants which it deems to have significant weaknesses that warrant
maintaining the plant in shutdown condition until the operator demonstrates
that adequate programs have been established and implemented to ensure
substantial improvement in the operation of the plant. The NRC's letter also
informed NU that this designation would require the NRC staff to obtain NRC
approval by vote prior to a restart of the unit.
The Company cannot predict when Millstone 3 will be allowed by the
NRC to restart, but believes that the unit will remain shut down for a
protracted period of time. During the period that Millstone 3 is out of
service, FG&E will continue to incur its proportionate share of the units
ongoing Operations and Maintenance (O&M) costs, and may incur additional O&M
costs and capital expenditures to meet NRC requirements. FG&E will also
incur costs to replace the power that was expected to be generated by the
unit. During the outage FG&E has been recovering approximately $35,000 per
month in replacement power costs through its fuel adjustment clause, which is
subject to periodic review by the MDPU.
ENVIRONMENTAL
The Company continues to work with federal and state environmental
agencies to identify and assess environmental issues at two former gas
manufacturing sites, the Sawyer Passway ("Sawyer Passway") and Logan Street
("Logan Street") sites, operated by Fitchburg Gas and Electric Light Company,
the Company's combination gas and electric operating subsidiary.
In December 1994 the Company accepted a Tier 1B permit from the
Massachusetts Department of Environmental Protection (DEP) to address the
Sawyer Passway site in Fitchburg, Massachusetts pursuant to the requirements
of the Massachusetts Contingency Plan. A supplemental Phase II field
investigation was conducted at the Site in July and August of 1996. Results
of the investigation confirm, in the Phase II Investigation Report
(the "Report"), the presence of some contamination, however, the Report
indicates the identified contamination does not present "an imminent hazard
to health, safety or the environment." The Phase II Investigation Report
and the Risk Characterization was submitted to the DEP on January 31, 1997.
Phase III, the Identification and Selection of Comprehensive Remedial Action
Alternatives, has been delayed until June 30, 1997 to permit investigation
of redevelopment alternatives on this site.
The Company also conducted a Phase I assessment of the Logan Street
Site on April 12, 1995. Results of that investigation suggest that there is
some evidence of both groundwater and soil contamination. The site was
numerically ranked using the Massachusetts Contingency Plan Numerical Ranking
System Scoresheet and was classified as a Tier II Site. Currently, site
closeout options are being investigated.
The costs of such assessments and any remedial action determined to
be necessary will initially be funded from traditional sources of capital and
recovered from customers under a rate recovery mechanism approved by the
Massachuestts Department of Public Utilities. The Company also has a number
of liability insurance policies that may provide coverage for environmental
remediation at this site. Because these investigations are at an early stage
management cannot, at this time, predict the costs of future analysis and
remediation.
NEW ACCOUNTING STANDARDS
During 1996, the Company adopted SFAS No. 121, "Accounting for the
Impairment of Long-Lived Assets and For Long-Lived Assets to be Disposed of.
" This Statement requires a review of long-lived assets for impairment
whenever events or changes in circumstances indicate that the carrying amount
of an asset may not be recoverable from the estimated future undiscounted cash
flows associated with the asset. The adoption of this standard did not have
a material impact on the financial position of the Company.
ITEM 8 -- FINANCIAL STATEMENTS AND SUPPLEMENTAL DATA
Report of Independent Certified Public Accountants
To the Shareholders of Unitil Corporation:
We have audited the accompanying consolidated balance sheets and
consolidated statements of capitalization of Unitil Corporation and
subsidiaries as of December 31, 1996 and 1995, and the related consolidated
statements of earnings, cash flows and changes in common stock equity for
each of the three years in the period ended December 31, 1996. These
financial statements are the responsibility of the Company's management.
Our responsibility is to express an opinion on these financial statements
based on our audits.
We conducted our audits in accordance with generally accepted
auditing standards. Those standards require that we plan and perform the
audit to obtain reasonable assurance about whether the financial statements
are free of material misstatement. An audit includes examining, on a test
basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used
and significant estimates made by management, as well as evaluating the
overall financial statement presentation. We believe our audits provide a
reasonable basis for our opinion.
In our opinion, the financial statements referred to above present
fairly, in all material respects, the consolidated financial position of
Unitil Corporation and subsidiaries as of December 31, 1996 and 1995, and the
consolidated results of their operations and their consolidated cash flows
for each of the three years in the period ended December 31, 1996, in
conformity with generally accepted accounting principles.
We have also audited Schedule VIII of Unitil Corporation and
subsidiaries as of December 31, 1996 and for the three years then ended
included in Part IV Item 14(a)(2). In our opinion, the schedule presents
fairly, in all material respects, the information required to be set forth
therein.
GRANT THORNTON LLP
Boston, Massachusetts
February 7, 1997
CONSOLIDATED BALANCE SHEETS
ASSETS
December 31, 1996 1995
Utility Plant:
Electric $157,874,414 $148,458,414
Gas 28,729,277 27,220,705
Common 18,779,677 8,494,093
Construction Work in Progress 2,161,114 6,003,991
Utility Plant 207,544,482 190,177,203
Less: Accumulated Depreciation 63,786,756 60,682,742
Net Utility Plant 143,757,726 129,494,461
Other Property & Investments 42,448 42,448
Current Assets:
Cash 2,902,842 3,397,931
Accounts Receivable - Less
Allowance for Doubtful Accounts
of $660,114 and $622,596 16,383,323 14,931,699
Materials and Supplies 2,478,932 2,275,865
Prepayments 480,453 434,727
Accrued Revenue 8,859,188 2,577,715
Total Current Assets 31,104,738 23,617,937
Deferred Assets:
Debt Issuance Costs 828,689 885,258
Cost of Abandoned Properties 25,432,258 27,254,791
Prepaid Pension Costs 7,347,635 6,689,093
Other Deferred Assets 23,594,289 23,718,296
Total Deferred Assets 57,202,871 58,547,438
TOTAL $232,107,783 $211,702,284
(The accompanying Notes are an integral part of these statements.)
CAPITALIZATION AND LIABILITIES
December 31, 1996 1995
Capitalization:
Common Stock Equity $67,974,260 $63,894,789
Preferred Stock, Non-Redeemable,
Non-Cumulative 225,000 225,000
Preferred Stock, Redeemable,
Cumulative 3,665,900 3,773,900
Long-Term Debt, Less Current
Portion 60,917,000 62,211,000
Total Capitalization 132,782,160 130,104,689
Capitalized Leases, Less Current
Portion 4,629,832 3,732,947
Current Liabilities:
Long-Term Debt, Current Portion 1,294,000 1,294,000
Capitalized Leases, Current Portion 1,000,210 741,832
Accounts Payable 15,103,925 14,565,075
Short-Term Debt 21,400,000 2,700,000
Dividends Declared and Payable 191,246 170,796
Refundable Customer Deposits 1,585,116 3,214,502
Taxes Payable (Refundable) (147,938) 216,596
Interest Payable 1,484,166 1,425,876
Other Current Liabilities 2,043,846 1,225,445
Total Current Liabilities 43,954,571 25,554,122
Deferred Liabilities:
Investment Tax Credits 1,610,117 1,803,821
Other Deferred Liabilities 8,488,593 9,763,878
Total Deferred Liabilities 10,098,710 11,567,699
Deferred Income Taxes 40,642,510 40,742,827
TOTAL $232,107,783 $211,702,284
(The accompanying Notes are an integral part of these statements.)
CONSOLIDATED STATEMENTS OF EARNINGS
Year Ended December 31,
1996 1995 1994
Operating Revenues:
Electric $149,696,296 $138,099,371 $134,096,627
Gas 21,104,498 17,629,879 18,694,703
Other 45,427 940,954 624,560
Total Operating Revenues 170,846,221 156,670,204 153,415,890
Operating Expenses:
Fuel and Purchased Power 100,768,116 92,346,024 90,342,737
Gas Purchased for Resale 13,322,853 10,522,742 11,139,311
Operation and Maintenance 24,110,140 22,824,218 21,903,619
Depreciation 6,953,720 6,315,613 6,129,617
Amortization of Abandoned
Properties 1,822,533 1,518,047 1,605,640
Provisions for Taxes:
Local Property and Other 4,983,229 4,784,109 4,384,032
Federal and State Income 4,612,534 4,134,826 4,156,479
Total Operating Expenses 156,573,125 142,445,579 139,661,435
Operating Income 14,273,096 14,224,625 13,754,455
Non-Operating (Income) Expenses (627,201) 216,860 64,108
Income Before Interest Expense 14,900,297 14,007,765 13,690,347
Interest Expense, Net 6,171,254 5,638,969 5,652,148
Net Income 8,729,043 8,368,796 8,038,199
Less Dividends on Preferred
Stock 277,758 283,749 291,543
Net Income Applicable to Common
Stock $8,451,285 $8,085,047 $7,746,656
Average Common Shares Outstanding 4,354,297 4,298,752 4,234,062
Earnings Per Average Common Share $1.94 $1.88 $1.83
(The accompanying Notes are an integral part of these statements.)
CONSOLIDATED STATEMENTS OF CAPITALIZATION
December 31,
1996 1995
Common Stock Equity
Common Stock, No Par Value (Authorized
- 8,000,000 shares; $33,984,409 $32,822,673
Outstanding - 4,384,065 and
4,329,585 Shares)
Stock Options 1,505,666 1,299,177
Retained Earnings 32,484,185 29,772,939
Total Common Stock Equity 67,974,260 63,894,789
Preferred Stock
CECo Preferred Stock, Non-Redeemable,
N on-Cumulative: 225,000 225,000
6% Series, $100 Par Value
CECo Preferred Stock, Redeemable, Cumulative: 215,000 215,000
8.70% Series, $100 Par Value
E&H Preferred Stock, Redeemable, Cumulative:
5% Series, $100 Par Value 91,000 98,000
6% Series, $100 Par Value 168,000 168,000
8.75% Series, $100 Par Value 344,300 344,300
8.25% Series, $100 Par Value 406,000 406,000
FG&E Preferred Stock, Redeemable, Cumulative:
5.125% Series, $100 Par Value 1,034,600 1,076,600
8% Series, $100 Par Value 1,407,000 1,466,000
Total Preferred Stock 3,890,900 3,998,900
Long-Term Debt
CECo First Mortgage Bonds:
Series C, 6.75%, Due January 15, 1998 1,552,000 1,584,000
Series H, 9.43%, Due September 1, 2003 5,850,000 6,500,000
Series I, 8.49%, Due October 14, 2024 6,000,000 6,000,000
E&H First Mortgage Bonds:
Series E, 6.75%, Due January 15, 1998 504,000 511,000
Series H, 8.50%, Due December 15, 2002 805,000 910,000
Series J, 9.43%, Due September 1, 2003 4,500,000 5,000,000
Series K, 8.49%, Due October 14, 2024 9,000,000 9,000,000
FG&E Long-term Notes:
Twelve year Notes, 8.55%, Due March 31, 2004 15,000,000 15,000,000
Thirty year Notes, 6.75%, Due November 30, 2023 19,000,000 19,000,000
Total Long-Term Debt 62,211,000 63,505,000
Less: Long-Term Debt, Current Portion 1,294,000 1,294,000
Total Long-Term Debt, Less Current Portion 60,917,000 62,211,000
Total Capitalization $132,782,160 $130,104,689
(The accompanying Notes are an integral part of these statements.)
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year Ended December 31, 1996 1995 1994
Cash Flows From Operating Activities:
Net Income $8,729,043 $8,368,796 $8,038,199
Adjustments to Reconcile Net Income to
Net Cash Provided by Operating Activities:
Depreciation and Amortization 8,776,253 7,833,660 7,735,257
Deferred Taxes 457,712 (314,365) 257,630
Amortization of Investment Tax Credit (193,704) (202,347) (210,676)
Amortization of Debt Issuance Costs 56,571 72,252 63,882
Provision for Doubtful Accounts 911,628 889,320 717,735
(Gain) Loss on Taking of Land and Bldg (875,000) 140,698 ----
Changes in Assets and Liabilities:
(Increase) Decrease In:
Accounts Receivable (2,363,251) (2,539,334) (281,549)
Materials and Supplies (203,067) (185,886) 437,485
Prepayments and Prepaid Pension (704,268) (913,405) (704,790)
Accrued Revenue (6,281,473) (285,418) 1,354,192
Increase (Decrease) In:
Accounts Payable 538,850 2,074,034 (949,245)
Refundable Customer Deposits (1,629,386) 731,723 744,325
Taxes and Interest Payable (306,244) 611,238 (396,700)
Other, Net (684,418) 736,870 (456,528)
Net Cash Provided by Operating Activities 6,229,246 17,017,836 16,349,217
Cash Flows From Investing Activities:
Acq. of Property, Plant & Equipment (19,358,615) (14,644,963) (8,943,491)
Proceeds from Taking of Land & Bldg 875,000 2,000,000 ----
Net Cash Used in Investing Activities (18,483,615) (12,644,963) (8,943,491)
Cash Flows from Financing Activities:
Proceeds From (Repayment of) ST Debt 18,700,000 2,700,000 (8,400,000)
Proceeds From Issuance of LT Debt ---- ---- 15,000,000
Repayment of Long-Term Debt (1,294,000) (2,075,321) (6,797,773)
Dividends Paid (5,997,348) (5,760,286) 5,514,283)
Issuance of Common Stock 1,161,735 1,070,689 1,108,976
Retirement of Preferred Stock (108,000) (94,700) (104,100)
Repayment of Capital Lease Obligations (703,107) (625,447) (594,209)
Net Cash Provided by (Used in) Financing 11,759,280 (4,785,065) (5,301,389)
Net (Decrease) Increase in Cash (495,089) (412,192) 2,104,337
Cash at Beginning of Year 3,397,931 3,810,123 1,705,786
Cash at End of Year $2,902,842 $3,397,931 $3,810,123
Supplemental Cash Flow Information:
Interest Paid $6,132,611 $5,942,933 $5,518,586
Federal Income Taxes Paid $3,982,000 $3,435,000 $4,141,527
Non-Cash Financing Activities:
Capital Leases Incurred $1,858,370 $1,262,685 $237,243
(The accompanying Notes are an integral part of these statements.)
CONSOLIDATED STATEMENTS OF
CHANGES IN COMMON STOCK EQUITY
Deferred
Stock
Common Option Retained
Shares Plan Earnings Total
Balance at January 1, 1994 $30,643,009 $910,892 $24,679,876 $56,233,777
Net Income for 1994 8,038,199 8,038,199
Dividends on preferred shares (291,543) (291,543)
Dividends on common shares -
at an annual rate of $1.24 per share (5,243,516) (5,243,516)
Stock Option Plan 180,475 180,475
Exercised stock options-4,110 shares 71,166 (29,169) 41,997
Issuance of 58,229 common shares(a)1,037,809 1,037,809
Balance at December 31, 1994 31,751,984 1,062,198 27,183,016 59,997,198
Net Income for 1995 8,368,796 8,368,796
Dividends on preferred shares (283,749) (283,749)
Dividends on common shares -
at an annual rate of $1.28 per share (5,495,124) (5,495,124)
Stock Option Plan 248,127 248,127
Exercised stock options-3,291 shares 61,190 (11,148) 50,042
Issuance of 58,457 common shares(a)1,009,499 1,009,499
Balance at December 31, 1995 32,822,673 1,299,177 29,772,939 63,894,789
Net Income for 1996 8,729,043 8,729,043
Dividends on preferred shares (277,758) (277,758)
Dividends on common shares -
at an annual rate of $1.32 per share (5,740,039) (5,740,039)
Stock Option Plan 237,044 237,044
Exercised stock options-2,400 shares 50,475 (30,555) 19,920
Issuance of 52,081 common shares(a)1,111,261 1,111,261
Balance at December 31, 1996 $33,984,409 $1,505,666 $32,484,185 $67,974,260
(a) Shares sold and issued in connection with the Company's Dividend
Reinvestment and Stock Purchase Plan and Employee 401(k) Tax Deferred
Savings and Investment Plan (See Note 2).
(The accompanying Notes are an integral part of these statements.)
Note 1: Summary of Significant Accounting Policies
Nature of Operations --- The Company is registered with the Securities and
Exchange Commission (SEC) as a holding company (with subsidiaries providing
electric service and electric power supply in New Hampshire, electric and gas
service in Massachusetts and consulting and other services on energy related
matters) under the Public Utility Holding Company Act of 1935 (1935 Act).
In addition, the Company and several of its wholly-owned utility operating
subsidiaries -- Concord Electric Company (CECo), Exeter & Hampton Electric
Company (E&H), Fitchburg Gas and Electric Light Company (FG&E), and Unitil
Power Corp. (Unitil Power) -- are subject to regulation by various other
agencies. With respect to their rates and accounting practices, two of the
retail subsidiaries, CECo and E&H, are subject to regulation by the New
Hampshire Public Utilities Commission (NHPUC), FG&E is subject to regulation
by the Massachusetts Department of Public Utilities (MDPU), and Unitil Power
is regulated by the Federal Energy Regulatory Commission (FERC). CECo, E&H,
FG&E and Unitil Power conform with generally accepted accounting principles,
as applied in the case of regulated public utilities, and conform with the
accounting requirements and ratemaking practices of the regulatory authorities
having jurisdiction.
Basis of Presentation
Principles of Consolidation --- Unitil Corporation (the Company) is the parent
company of the Unitil System (the System). The consolidated financial
statements include the accounts of the Company and all of its wholly-owned
subsidiaries. All material intercompany balances and transactions have been
eliminated in consolidation.
Use of Estimates --- The preparation of financial statements in conformity
with generally accepted accounting principles requires management to make
estimates and assumptions that affect the reported amounts of assets and
liabilities, and requires disclosure of contingent assets and liabilities
at the date of the financial statements and the reported amounts of revenues
and expenses during the reporting period. Actual results could differ from
those estimates.
Revenue Recognition --- The Companys operating subsidiaries record electric
and gas operating revenues based upon the amount of electricity and gas
delivered to customers through the end of the accounting period.
Depreciation --- Depreciation provisions for the Companys utility operating
subsidiaries are determined on a group straight-line basis. Provisions for
depreciation were equivalent to the following composite rates, based on the
average depreciable property balances at the beginning and end of each year:
1996 - 3.45 percent; 1995 - 3.48 percent, and 1994 - 3.49 percent.
Amortization of Abandoned Properties --- FG&E is recovering a portion of its
former investment in the Seabrook Nuclear Power Plant in rates to its customers
through a Seabrook Amortization Surcharge as ordered by the MDPU.
Federal Income Taxes --- Deferred tax assets and liabilities are determined
based on differences between the financial reporting and tax bases of assets
and liabilities, and are measured by applying tax rates applicable to the
taxable years in which those differences are expected to reverse. The Tax
Reduction Act of 1986 eliminated investment tax credits. Investment tax
credits generated prior to 1986 are being amortized, for financial reporting
purposes, over the productive lives of the related assets.
New Accounting Standard --- During 1996, the Company adopted SFAS No. 121,
"Accounting for the Impairment of Long-Lived Assets and For Long-Lived Assets
to be Disposed of." This Statement requires a review of long-lived assets
for impairment whenever events or changes in circumstances indicate that the
carrying amount of an asset may not be recoverable from the estimated future
undiscounted cash flows associated with the asset. The adoption of this
standard did not have a material impact on the financial position of the
Company.
Reclassifications --- Reclassifications are made periodically to amounts
previously reported to conform with current year presentation.
Note 2: Common Stock
New Shares Issued --- During 1996, the Company raised $1,111,261 of additional
common equity capital through the issuance of 52,081 shares of common stock
in connection with the Dividend Reinvestment and Stock Purchase Plan and
Employee 401(k) Tax Deferred Savings and Investment Plan. The Dividend
Reinvestment and Stock Purchase Plan provides participants in the plan a
method for investing cash dividends on the Company's Common Stock and cash
payments in additional shares of the Company's Common Stock. The Employee
401(k) Tax Deferred Savings and Investment Plan is described in Note 9 below.
In 1995, the Company raised $1,009,499 of additional common equity capital
through the issuance of 58,457 shares of common stock in connection with
these plans.
The Company maintains a Key Employee Stock Option Plan (KESOP), which provides
for the granting of options to key employees. The number of shares granted
under this plan, as well as the terms and conditions of each grant, are
determined by the Board of Directors, subject to plan limitations. All options
granted under the KESOP vest upon grant and expire within ten years of the
grant date. No option can be issued under the current plan after 1999. The
plan provides options and dividend equivalents on options granted, which are
recorded at fair value as compensation expense. The total compensation
expenses recorded by the Company with respect to this plan were $237,044,
$248,127 and $180,475 for the years ended December 31, 1996, 1995 and 1994,
respectively.
Share Option Activity of the KESOP is presented in the following table:
1996 1995 1994
Beginning Options Outstanding & Exercisable 173,362 147,981 142,354
Options Granted 1,000 17,000 ---
Dividend Equivalents Earned 10,533 11,672 9,737
Options Exercised (2,400) (3,291) (4,110)
Options Canceled --- --- ---
Ending Options Outstanding & Exercisable 182,495 173,362 147,981
Range of Option Grant Price per Share $12.11-$18.28 $12.11-$14.93 $12.11-$17.74
The Company has adopted Statement of Financial Accounting Standards
(SFAS) No. 123, "Accounting for Stock Based Compensation," and recognizes
compensation costs at fair value. The Company has omitted certain disclosures
relating to SFAS No. 123, as the recording of compensation expense did not
materially differ from the way the Company had previously recorded this
expense.
Restrictions on Retained Earnings ---Unitil Corporation has no restriction
on the payment of common dividends from retained earnings. Its three retail
distribution subsidiaries do have restrictions. Under the terms of the First
Mortgage Bond Indentures, CECo and E&H had $5,513,077 and $8,093,982,
respectively, available for the payment of cash dividends on their common
stock at December 31, 1996. Under the terms of long-term debt Purchase
Agreements, FG&E had $13,712,366 of retained earnings available for the
payment of cash dividends on its common stock at December 31, 1996.
Note 3: Preferred Stock
Certain of the Unitil subsidiaries have redeemable Cumulative Preferred Stock
outstanding and one subsidiary, CECo, has a Non-Redeemable, Non-Cumulative
Preferred Stock issue outstanding. All such subsidiaries are required to offer
to redeem annually a given number of shares of each series of Redeemable
Cumulative Preferred Stock and to purchase such shares that shall have been
tendered by holders of the respective stock. All such subsidiaries may redeem,
at their option, the Redeemable Cumulative Preferred Stock at a given redemption
price, plus accrued dividends.
The aggregate purchases of Redeemable Cumulative Preferred Stock during 1996,
1995 and 1994 were: 1996 - $108,000; 1995 - $94,700; and 1994 - $104,100.
The aggregate amount of sinking fund requirements of the Redeemable Cumulative
Preferred Stock for each of the five years following 1996 are $206,000 per
year.
Note 4: Long-Term Debt
Under the terms of both CECos Indenture of Mortgage and Deed of Trust and the
supplemental indenture thereto relating to long-term debt, the sinking fund
requirements of CECo's Series C Bonds may be satisfied by certifying to the
Mortgage Trustee net additional property in lieu of making cash redemptions.
In 1996, total sinking fund payments for CECo and E&H relating to long-term
debt amounted to $1,294,000. In 1995, CECo satisfied its requirements with
respect to its Series C Bonds by certifying to the Mortgage Trustee net
additional property.
Certain of the loan agreements contain provisions which, among other things,
limit the incurring of additional long-term debt.
The aggregate amount of sinking fund requirements and normal scheduled
redemptions for each of the five years following 1996 are: 1997 - $1,294,000;
1998 - $4,339,000; 1999 - $2,290,000; 2000 - $2,290,000, and 2001 - $4,940,000.
The fair value of the Companys long-term debt is estimated based on the quoted
market prices for the same or similar issues, or on the current rates offered
to the Company for debt of the same remaining maturities. In management's
opinion, the carrying value of the debt approximated its fair value at December
31, 1996 and 1995.
Note 5: Credit Arrangements
At December 31, 1996, the Company had unsecured committed bank lines for
short-term debt aggregating $23,000,000 with four banks for which it pays
commitment fees. At December 31, 1996, the unused portion of the committed
credit lines outstanding was $1,600,000. The average interest rates on all
short-term borrowings were 5.79% and 6.59% during 1996 and 1995, respectively.
Note 6: Leases
The Companys subsidiaries conduct a portion of their operations in leased
facilities and also lease some of their machinery and office equipment.
FG&E has a facility lease for twenty-two years which began in February 1981.
The lease allows five, five-year renewal periods at the option of FG&E.
The equipment leases include a twenty-five-year lease, which began on April
1, 1973, for a combustion turbine and a liquefied natural gas storage and
vaporization facility. This lease provides for a ten-year renewal period at
the option of FG&E. In addition, Unitils subsidiaries lease some equipment
under operating leases.
The following is a schedule of the leased property under capital leases by
major classes:
Asset Balances at
December 31,
Classes of Utility Plant 1996 1995
Electric $2,054,025 $2,054,025
Gas 726,329 726,329
Common 5,822,813 5,061,846
Gross Plant 8,603,167 7,842,200
Less: Accumulated Depreciation 2,973,125 3,367,421
Net Plant $5,630,042 $4,474,779
The following is a schedule by years of future minimum lease payments and
present value of net minimum lease payments under capital and operating
leases as of December 31, 1996:
Year Ending December 31,
Capital Operating
1997 $1,637,056 $63,902
1998 1,348,372 34,022
1999 1,222,057 652
2000 1,013,754
2001 824,253
2002 - 2006 1,899,428
Total Minimum Lease Payments $7,944,920 $98,576
Less: Amount Representing Interest 2,314,878
Present Value of Net Minimum Lease Payments $5,630,042
Total rental expense charged to operations for the years ended December 31,
1996, 1995 and 1994 amounted to $161,000; $447,000; and $320,000, respectively.
Note 7: Income Taxes
Federal Income Taxes were provided for the following items for the years ended
December 31, 1996, 1995 and 1994, respectively:
1996 1995 1994
Current Federal Tax Provision:
Operating Income $3,658,222 $3,959,976 $3,497,311
Amortization of Investment Tax Credits (193,704) (202,347) (210,676)
Total Current Federal Tax Provision 3,464,518 3,757,629 3,286,635
Deferred Federal Tax Provision:
Accelerated Tax Depreciation 602,761 545,233 590,655
Abandoned Properties (654,985) (578,255) (611,620)
Allowance for Funds Used During Construction
("AFUDC") and Overheads (71,751) (73,191) (73,192)
Post Retirement Benefits Other Than Pensions(20,279) (19,941) (27,162)
Deferred Maintenance Cost and Other (174,549) (86,178) (122,382)
Percentage Repair Allowance 123,871 106,630 145,927
Deferred Advances 303,699 (482,112) 26,967
Deferred Pensions 211,888 289,622 256,867
Total Deferred Federal Tax Provision 320,655 (298,192) 186,060
Total Federal Tax Provision $3,785,173 $3,459,437 $3,472,695
The components of the Federal and State income tax provisions
reflected in the accompanying consolidated statements of earnings for the
years ended December 31, 1996, 1995 and 1994 were as follows:
1996 1995 1994
Federal:
Current $3,658,222 $3,959,976 $3,497,311
Deferred 320,655 (298,192) 186,060
Amortization of Investment Tax Credits (193,704) (202,347) (210,676)
Total Federal Tax Provision 3,785,173 3,459,437 3,472,695
State:
Current 690,303 691,563 612,214
Deferred 137,058 (16,174) 71,570
Total State Tax Provision 827,361 675,389 683,784
Total Provision for Federal and State
Income Taxes $4,612,534 $4,134,826 $4,156,479
The differences between the Company's provisions for Federal Income Taxes and
the provisions calculated at the statutory federal tax rate, expressed in
percentages, are shown below:
Year Ended December 31,
1996 1995 1994
Statutory Federal Income Tax Rate 34% 34% 34%
Income Tax Effects of:
Investment Tax Credits (2) (2) (2)
Donation of Appreciated Land --- (1) ---
Federal Income Tax - Prior (1) (1) ---
Other, Net (1) (1) (2)
Effective Federal Income Tax Rate 30% 29% 30%
Temporary differences which gave rise to deferred tax assets and liabilities
are shown below:
Deferred Income Taxes for the Year Ended December 31,
1996 1995
Accelerated Depreciation $24,374,031 $23,971,624
Abandoned Property 9,687,654 10,381,893
Contributions in Aid to Construction (2,810,811) (3,166,565)
Percentage Repair Allowance 1,692,616 1,599,813
Cathodic Protection 349,384 294,978
Retirement Loss 1,526,116 1,288,346
Deferred Pensions 2,518,284 2,303,456
AFUDC 61,992 78,878
Overheads 301,093 360,470
KESOP (534,982) (451,009)
Bad Debts (249,670) (235,785)
Accumulated Deferred (SFAS 109) 3,884,726 4,442,755
Other (157,923) (126,027)
Total Deferred Income Taxes $40,642,510 $40,742,827
Note 8: Joint Ownership Units
FG&E is participating, on a tenancy-in-common basis with other New England
utilities, in the ownership of three generating units. New Haven Harbor is a
dual-fired oil-and-gas station, and Wyman Unit No. 4 is an oil-fired station.
They have been in commercial operation since August 1975 and December 1978,
respectively. Millstone Unit No. 3, a nuclear generating unit, has been in
commercial operation since April 1986. Kilowatt-hour generation and operating
expenses of the joint ownership units are divided on the same basis as
ownership. FG&E's proportionate costs are reflected in the 1996 Consolidated
Statements of Earnings. Information with respect to these units as of December
31, 1996 is set forth in the table below:
Company's Share
Joint Ownership Proportionate Share of Amount of Utility Accumulated
Units State Ownership % Total MW Plant in Service Depreciation
Millstone Unit No.3 CT 0.2170 2.50 $11,469,857 $3,491,233
Wyman Unit No.4 ME 0.1822 1.13 408,141 273,023
New Haven Harbor CT 4.5000 20.12 7,065,274 5,057,037
23.75 $18,943,272 $8,821,293
Note 9: Benefit Plans
Pension Plans --- Four of the Companys subsidiaries have Retirement and Pension
plans and related Trust Agreements to provide retirement annuities for
participating employees at age 65. The entire cost of the plans is borne by
the respective subsidiaries.
Net periodic pension (income) cost for 1996, 1995 and 1994 included the
following components:
1996 1995 1994
Service Cost--Benefits Earned During the Period $703,148 $616,016 $693,340
Interest Cost on Projected Benefit Obligation 1,920,786 1,811,981 1,795,836
Expected Return on Plan Assets (4,836,448)(6,412,405)(2,714,751)
Net Amortization and Deferral 2,016,445 3,652,029 (20,546)
Net Periodic Pension (Income) Cost $(196,069) $(332,379) $(246,121)
The following table sets forth the plans funded status at December 31, 1996,
1995 and 1994:
Projected Benefit Obligation:
1996 1995 1994
Vested $21,394,580 $24,250,626 $19,970,389
Non-Vested 1,137,183 148,106 331,910
Accumulated 22,531,763 24,398,732 20,302,299
Due to Recognition of Future
Salary Increases 4,375,492 3,837,798 2,521,055
Total 26,907,255 28,236,530 22,823,354
Plan Assets at Fair Value 36,547,430 32,858,602 27,343,779
Funded Status 9,640,175 4,622,072 4,520,425
Unrecognized Net Loss (Gain) (2,625,660) 1,736,643 953,653
Unrecognized Prior Service Cost 111,232 124,718 138,204
Unrecognized Transition Obligation 221,888 205,660 189,432
Prepaid Pension Cost $7,347,635 $6,689,093 $5,801,714
Plan assets are invested in common stock, short-term investments and various
other fixed income security funds.
The weighted-average discount rates used in determining the projected benefit
obligation in 1996, 1995 and 1994 were 7.75%, 7.75%, and 8.25%, respectively,
while the rate of increase in future compensation levels was 4.50% for the last
three years. The expected long-term rates of return on assets in 1996, 1995
and 1994 were 9.25%, 9.50%, and 9.50%, respectively.
Unitil Service Corp. has a Supplemental Executive Retirement Plan (SERP).
The SERP is an unfunded retirement plan with participation limited to
executives selected by the Board of Directors. The cost associated with the
SERP amounted to $71,000; $60,000; and $53,000 for the years ended December
31, 1996, 1995 and 1994, respectively.
Employee 401(k) Tax Deferred Savings Plan--- The Company sponsors a defined
contribution plan (under Section 401 (k) of the Internal Revenue Code)
covering substantially all of the Company's employees. Participants may elect
to defer from 1% to 12% of current compensation to the plan. The Company
matches contributions, with a maximum matching contribution of 3% of current
compensation. Employees may direct the investment of their savings plan
balances into a variety of investment options, including a Company common
stock fund. Participants are 100% vested in contributions made on their behalf,
once they have completed three years of service. The Company's share of
contributions to the plan were $356,574; $301,486; and $284,248 for the
years ended December 31, 1996, 1995 and 1994, respectively.
Post-Retirement Benefits --- The Companys subsidiaries provide health care
benefits to retirees for a twelve-month period following their retirement.
The Companys subsidiaries continue to provide life insurance coverage to
retirees. Life insurance and limited health care post-retirement benefits
require the Company to accrue post-retirement benefits during the employees
years of service with the Company and the recognition of the actuarially
determined total post retirement benefit obligation earned by existing
retirees. At December 31, 1996 and 1995, the accumulated post retirement
benefit obligation (transition obligation) was approximately $342,000 and
$364,000, respectively, and the period cost associated with these benefits
for 1996 and 1995 was $132,447 and $132,172, respectively. This obligation is
being recognized on a delayed basis over the average remaining service period
of active participants and such period will not exceed 20 years. The Company
has omitted certain disclosures relating to SFAS No. 106, as the accumulated
post-retirement benefit obligation (transition obligation) is not material.
Note 10: Commitments and Contingencies
Environmental Matters --- The Company continues to work with federal and state
environmental agencies to identify and assess environmental issues at two
former gas manufacturing sites, the Sawyer Passway ("Sawyer Passway") and
Logan Street ("Logan Street") sites, operated by Fitchburg Gas and Electric
Light Company, the Company's combination gas and electric operating subsidiary.
In December 1994 the Company accepted a Tier 1B permit from the Massachusetts
Department of Environmental Protection (DEP) to address the Sawyer Passway
site in Fitchburg, Massachusetts pursuant to the requirements of the
Massachusetts Contingency Plan. A supplemental Phase II field investigation
was conducted at the Site in July and August of 1996. Results of the
investigation confirm, in the Phase II Investigation Report (the "Report"),
the presence of some contamination, however, the Report indicates the
identified contamination does not present "an imminent hazard to health,
safety or the environment." The Phase II Investigation Report and the Risk
Characterization was submitted to the DEP on January 31, 1997. Phase III, the
Identification and Selection of Comprehensive Remedial Action Alternatives, has
been delayed until June 30, 1997 to permit investigation of redevelopment
alternatives on this site.
The Company also conducted a Phase I assessment of the Logan Street Site on
April 12, 1995. Results of that investigation suggest that there is some
evidence of both groundwater and soil contamination. The site was
numerically ranked using the Massachusetts Contingency Plan Numerical Ranking
System Scoresheet and was classified as a Tier II Site. Currently, site
closeout options are being investigated.
The costs of such assessments and any remedial action determined to be
necessary will initially be funded from traditional sources of capital and
recovered from customers under a rate recovery mechanism approved by the
Massachuestts Department of Public Utilities. The Company also has a number
of liability insurance policies that may provide coverage for environmental
remediation at this site. Because these investigations are at an early stage
management cannot, at this time, predict the costs of future analysis and
remediation.
Regulatory Matters
Competition and Restructuring - Regulatory activity in both New Hampshire and
Massachusetts has focused on the restructuring of the electric industry and
the process of deregulating the retail sale of electric energy. In both states,
January 1, 1998 has been targeted as the beginning of competition, or "Choice
Date." Under these restructuring proposals, customers would be allowed to
choose their supplier of electricity from the competitive market, and have
their local utility deliver that electricity over its distribution systems at
regulated rates.
Unitil has been preparing for this restructuring by developing transition plans
that will move its utility subsidiaries into this new market structure in a
way that will ensure fairness in the treatment of the Companys assets and
obligations that are dedicated to the current regulated franchises and, at
the same time, provide choice for all customers. Simultaneous with this
transition process for Unitils regulated utilities, the Company is moving to
position its competitive market subsidiary, Unitil Resources, Inc., to pursue
growth areas both within and beyond the Companys traditional franchises in
all energy-related sectors, including electricity, gas, oil and propane.
New Hampshire In New Hampshire, House Bill 1392 (HB 1392) was signed into
law by the Governor in May 1996. HB 1392 establishes principles, standards
and a timetable for the New Hampshire Public Utilities Commission (NHPUC) to
implement full, open retail electric competition as early as January 1, 1998,
but no later than July 1, 1998. The bill also directs the NHPUC to set
interim access charges for the recovery of above market "stranded" power
supply costs and to make a final determination on these access charges within
two years of implementation of full competition.
As required by HB 1392, the NHPUC has set a procedural schedule for opening up
the state to retail competition. In connection with that procedural schedule,
the Company has filed with the NHPUC its "Customer Choice" Plan a transition
plan that guarantees electric consumers open access to the retail energy
supply market in New Hampshire. Under this plan, all of the Companys New
Hampshire customers will continue to enjoy Unitils very competitive electric
rates, among the lowest in New England, and also may benefit from future
market competition and the resulting energy savings. Unitils Customer Choice
Plan guarantees all its customers competitive retail delivery prices, open
and nondiscriminatory access to competitive electricity suppliers, reliable
electric service and comprehensive consumer protection standards. The Companys
Customer Choice Plan achieves these benefits and safeguards for consumers
while providing for full recovery of Unitils obligations that are dedicated
to serving customers in the Companys New Hampshire franchises.
In June 1996, the New Hampshire Retail Competition Pilot Program (Pilot
Program), mandated by legislation enacted a year earlier, became operational.
During the two-year term of the Pilot Program, up to 3% or some 17,000
electric consumers are allowed to choose from competing electric suppliers,
and have this supply delivered across the local utility system. More than
thirty electric suppliers, including Unitil Resources, the Companys
competitive market subsidiary, are currently authorized to market electricity
to Pilot Program participants. Unitil Resources began competitive marketing
efforts in May, and began making sales in June.
Under the Pilot Program, the NHPUC initially ordered Concord Electric Company
and Exeter & Hampton Electric Company, Unitils New Hampshire-based
distribution companies, to file tariffs which included a 10% discount to
encourage participation and a mechanism to protect nonparticipants from any
adverse cost consequences resulting from changes in power supply obligations.
Both these tariff items would have had a significant impact on the ability of
the Company to recover its power supply obligations. However, after filing
for reconsideration of the NHPUCs Order, the Company entered into a settlement
agreement with the NHPUC staff and the Office of the Consumer Advocate which
provides the Company an opportunity to mitigate any losses which may result
under the Pilot Program. The settlement was approved by the NHPUC on July 1,
1996. The Company also recorded in 1996, a one-time charge to earnings for
estimated losses relating to Pilot Program operations.
Massachusetts - In March 1996, the Massachusetts Department of Public
Utilities (MDPU) issued a Notice of Inquiry/Rulemaking, opening a new phase
in its investigation on the restructuring of the electric utility industry in
Massachusetts. Throughout 1996 the MDPU conducted a comprehensive information
gathering effort, including holding numerous legislative style public hearings.
On December 30, 1996, the MDPU issued a document entitled Electric Utility
Restructuring Plan: Model Rules and Legislative Proposal. In this document
the MDPU presented its framework, model rules and proposed legislation for a
restructured electric utility industry. On February 24, 1997, the
Massachusetts Governor filed legislation for electric industry restructuring
which is generally consistent with the MDPUs proposal.
The MDPUs proposed rules provide transition measures to accomplish the change
from a regulated industry to a competitive market, as early as January 1, 1998.
These measures include consumer safety and reliability standards,
environmental protection measures and a reasonable framework for the recovery
of utilities stranded costs related to generation investments and purchased
power obligations. Included in the proposed rules and regulations is the
requirement that each electric utility file "unbundled rates," that is,
separate rate components for distribution, transmission and generation services
and for access to the competitive supplier market. The MDPU has identified the
unbundling of rates as "critical to provide both customers and competitors
with the information they need to make decisions in a more competitive
environment." The MDPU has required that the unbundled rates be revenue
neutral for the Company, for each rate class, and for each customer. The
Company is required to submit unbundled rates by March 3, 1997 to become
effective on or after July 1, 1997.
The MDPU has been supportive of the settlement process as a way to expedite
electric utility restructuring in Massachusetts. On February 26, 1997, the
MDPU approved a restructuring plan filed by the Massachusetts Attorney General,
the Massachusetts Division of Energy Resources and numerous other parties in
the context of a settlement agreement with the states largest investor owned
utility. Under this plan, consumers will be allowed to choose an electricity
suppler beginning as early as January 1, 1998, and are guaranteed a 10% savings
on their electric bills. The plan requires the utility to divest itself of
ownership of all its generation plant, and provides the utility with the
opportunity to fully recover its stranded costs. It is likely that several
restructuring offers of settlement will be filed in the first half of 1997 by
other Massachusetts electric utilities. The Company is currently developing a
transition plan for its Massachusetts utility subsidiary and exploring the use
of the settlement process to expedite the restructuring process.
Rate Cases
The last formal regulatory hearings to increase base rates for Unitil's three
retail operating subsidiaries occurred in 1985 for Concord Electric Company,
1984 for Fitchburg Gas and Electric Light Company and 1981 for Exeter &
Hampton Electric Company. A majority of the System's operating revenues are
collected under various periodic rate adjustment mechanisms including fuel,
purchased power, cost of gas and conservation program cost recovery mechanisms.
Millstone Unit No. 3
Unitils Massachusetts operating subsidiary, Fitchburg Gas and Electric Light
Company (FG&E), has a 0.217% ownership in the Millstone Unit No. 3 (Millstone
3) nuclear generating unit which supplies it with 2.49 MW of electric capacity.
In January 1996 the Nuclear Regulatory Commission (NRC) placed Millstone 3 on
its watch list as a Category 2 facility, which calls for increased NRC
inspection attention. In March 1996 the NRC requested additional information
about the operation of the unit from Northeast Utilities (NU), the units
managing owner. As a result of an engineering evaluation completed by NU,
Millstone 3 was taken out of service on March 30, 1996. The NRC later informed
NU, in a letter dated June 28, 1996, that it had reclassified Millstone 3 as
a Category 3 facility. The NRC assigns this rating to plants which it deems
to have significant weaknesses that warrant maintaining the plant in shutdown
condition until the operator demonstrates that adequate programs have been
established and implemented to ensure substantial improvement in the operation
of the plant. The NRC's letter also informed NU that this designation would
require the NRC staff to obtain NRC approval by vote prior to a restart of the
unit.
The Company cannot predict when Millstone 3 will be allowed by the NRC to
restart, but believes that the unit will remain shut down for a protracted
period of time. During the period that Millstone 3 is out of service, FG&E
will continue to incur its proportionate share of the units ongoing Operations
and Maintenance (O&M) costs, and may incur additional O&M costs and capital
expenditures to meet NRC requirements. FG&E will also incur costs to replace
the power that was expected to be generated by the unit. During the outage
FG&E has been recovering approximately $35,000 per month in replacement power
costs through its fuel adjustment clause, which is subject to periodic review
by the MDPU.
Litigation --- The Company is also involved in other legal and administrative
proceedings and claims of various types which arise in the ordinary course of
business. In the opinion of the Company's management, based upon information
furnished by counsel and others, the ultimate resolution of these claims will
not have a material impact on the Company's financial position.
Purchased Power and Gas Supply Contracts --- FG&E and Unitil Power have
commitments under long-term contracts for the purchase of electricity and gas
from various suppliers. Generally, these contracts are for fixed periods and
require payment of demand and energy charges. Total costs under these contracts
are included in Electricity and Gas Purchased for Resale in the Consolidated
Statements of Earnings. These costs are normally recoverable in revenues
under various cost recovery mechanisms.
The status of the electric purchased power contracts at December 31, 1996,
was as follows:
Est. Annual Min.
Payments Which Cover
Unit 1996 Energy Purchased Contract Future Debt Service
Fuel Type MW Entitlement (MWHs) End-Date Requirements ($000)
Unitil Power
Oil 10.0 27,710 2005 None
Gas 22.5 96,016 2010 $1,871 [1]
Gas 1.5 8,097 2012 None
Oil/Gas 25.0 76,265 1996 None
Oil/Gas 23.0 28,532 1998 None
Oil/Gas 15.0 15,253 2006 None
Oil/Gas 10.0 8,125 2008 None
Coal 20.0 39,049 2009 None [2]
Coal/Oil 24.8 135,964 2005 None
Nuclear 25.5 182,634 1998 None
Nuclear 5.0 21,285 2005 None
Nuclear 10.1 87,854 2010 None
Nuclear 2.0 18,614 2013 None
Hydro 8.9 2001 $1,103 [3]
Refuse 6.0 44,746 2003 None
System 8.0 3,944 1996 None
System 18.3 402 2002 None
Various 16.0 25,010 1999 None
Various 229,673 Short-term None
FG&E
Nuclear 10.0 59,135 1996 None
Hydro 5.3 2001 $479 [3]
Hydro 3.0 19,114 2012 None
Wood 14.0 107,780 2012 None
System 15.0 41,819 2001 None
Various 233,998 Short-term None
Notes:
[1] Total estimated 1996 annualized capacity payments, including debt service
requirements.
[2] Contract was terminated in 1996 and replaced with a purchase power option
agreement.
[3] Total support charges including debt service requirements.
Note 11: Segment Information
The following additional information is presented about the electric
and gas operations of the Company:
Electric Operations 1996 1995 1994
Operating Revenues $149,696,296 $138,099,371 $134,096,627
Operating Income Before Income Taxes $16,587,166 $16,781,348 $15,884,879
Identifiable Assets as of December 31 $179,999,328 $174,984,327 $172,350,572
Depreciation $6,098,187 $5,504,701 $5,359,212
Construction Expenditures $10,833,786 $9,158,920 $7,109,091
Gas Operations 1996 1995 1994
Operating Revenues $21,104,498 $17,629,879 $18,694,703
Operating Income Before Income Taxes $2,298,464 $1,578,103 $2,026,055
Identifiable Assets as of December 31 $33,472,548 $30,446,104 $29,065,750
Depreciation $855,533 $810,912 $770,405
Construction Expenditures $1,915,446 $2,007,922 $1,816,390
Total Company 1996 1995 1994
Electric and Gas Operating Revenues $170,800,794 $155,729,250 $152,791,330
Other Revenue 45,427 940,954 624,560
Total Operating Revenues $170,846,221 $156,670,204 $153,415,890
Operating Income Before Income Taxes $18,885,630 $18,359,451 $17,910,934
Income Tax Expense 4,612,534 4,134,826 4,156,479
Non-Operating Income (Expense) (627,201) 216,860 64,108
Net Interest and Other Expenses 6,171,254 5,638,969 5,652,148
Net Income $8,729,043 $8,368,796 $8,038,199
Dividend Requirements on Preferred Stock 277,758 283,749 291,543
Net Income Applicable to Common Stock $8,451,285 $8,085,047 $7,746,656
Identifiable Assets as of December 31 $213,471,876 $205,430,431 $201,416,322
Unallocated Assets 18,635,907 6,271,853 3,105,139
Total Assets as of December 31 $232,107,783 $211,702,284 $204,521,461
Depreciation $6,953,720 $6,315,613 $6,129,617
Construction Expenditures $19,358,615 $14,644,963 $8,943,491
Expenses used to determine operating income before taxes are charged
directly to either segment or are allocated in accordance with factors
contained in cost of service studies which were included in rate applications
approved by the NHPUC and MDPU. Assets allocated to each segment are based
upon specific identification of such assets provided by Company records.
Assets not so identified represent primarily working capital items and real
property.
Item 9. Changes In And Disagreements With Accountants On Accounting And
Financial Disclosure
None
PART III
Item 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
Information required by this Item is set forth in Exhibit 99.1 on pages 2
through 6 of the 1996 Proxy Statement.
Item 11. EXECUTIVE COMPENSATION
Information required by this Item is set forth in Exhibit 99.1 on pages 7
through 11 of the 1996 Proxy Statement.
Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
Information required by this Item is set forth in Exhibit 99.1 on pages 2
through 4 of the 1996 Proxy Statement and is incorporated herein by
reference.
Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
None
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K
(a) (1) and (2) -
LIST OF FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES
The following financial statements are included herein under Part II,
Item 8, Financial Statements and Supplementary Data.
Report of Independent Certified Public Accountants
Consolidated Balance Sheets - December 31, 1996 and 1995
Consolidated Statements of Earnings - for the years ended
December 31, 1996, 1995 and 1994
Consolidated Statements of Capitalization - December 31, 1996 and 1995
Consolidated Statements of Cash Flows
for the years ended December 31, 1996, 1995 and 1994
Consolidated Statements of Changes in Common Stock Equity -
for the years ended December 31, 1996, 1995 and 1994
Notes to Consolidated Financial Statements
The following consolidated financial statement schedules of the
Company and subsidiaries are included in Item 14(d):
Report of Independent Certified Public Accountants
Schedule VIII Valuation and Qualifying Accounts for December 31,
1996; 1995 and 1994
All other schedules for which provision is made in the applicable
accounting regulation of the Securities and Exchange Commission are not
required under the related instructions, are inappropriate, or information
required is included in the financial statements or notes thereto and,
therefore, have been omitted.
(3) - List of Exhibits
Exhibit No. Description of Exhibit Reference*
3.1 Articles of Incorporation Exhibit 3.1 to Form
of the Company. S-14 Registration
Statement 2-93769
3.2 Articles of Amendment to the
Articles of Incorporation
filed on March 4, 1992 and Exhibit 3.2 to Form
April 30, 1992. 10-K for 1992
3.3 By-Laws of the Company. Exhibit 3.2 to
Form S-14 Registration
Statement 2-93769
3.4 Articles of Exchange of Concord
Electric Company (CECo),
Exeter & Hampton Exhibit 3.3 to
Electric Company (E&H) 10-K
and the Company for 1984
3.5 Articles of Exchange of CECo,
E&H, and the Company -
Stipulation of the Parties Exhibit 3.4 to
Relative to Recordation and Form 10-K
Effective Date. for 1984
3.6 The Agreement and Plan of Merger
dated March 1, 1989 among the Exhibit 25(b) to
Company, Fitchburg Gas and Electric Form 8-K
Light Company (FG&E) and dated
UMC Electric Co., Inc. (UMC). March 1, 1989
3.7 Amendment No. 1 to The Agreement
and Plan of Merger dated March 1, Exhibit 28(b) to
1989 among the Company, FG&E Form 8-K, dated
and UMC December 14, 1989
4.1 Indenture of Mortgage and Deed of
Trust dated July 15, 1958 of
CECo relating to First
Mortgage Bonds, Series B, 4 3/8%
due September 15, 1988 and all
series unless supplemented. **
4.2 First Supplemental Indenture
dated January 15, 1968 relating
to CECo's First Mortgage
Bonds, Series C, 6 3/4% due January
5, 1998 and all additional series
unless supplemented. **
4.3 Second Supplemental Indenture
dated November 15, 1971 relating
to CECo's First Mortgage
Bonds, Series D, 8.70% due November
15, 2001 and all additional series
unless supplemented. **
4.4 Fourth Supplemental Indenture
dated March 28, 1984 amending
CECo's Original First Mortgage
Bonds Indenture, and First, Second and
Third Supplemental Indentures
and all additional series unless supplemented. **
4.5 Fifth Supplemental Indenture
dated June 1, 1984 relating
to CECo's First Mortgage
Bonds, Series F, 14 7/8% due June 1,
1999 and all additional series
unless supplemented. **
4.6 Sixth Supplemental Indenture
dated October 29, 1987 relating
to CECo's First Mortgage
Bonds, Series G, 9.85% due October Exhibit 4.6 to
15, 1997 and all additional series Form 10-K
unless supplemented. for 1987
4.7 Seventh Supplemental Indenture
dated August 29, 1991 relating
to CECo's First Mortgage
Bonds, Series H, 9.43% due September Exhibit 4.7 to
1, 2003 and all additional series Form 10-K
unless supplemented. for 1991
4.8 Eighth Supplemental Indenture
dated October 14, 1994 relating
to CECo's First Mortgage Bonds, Exhibit 4.8 to
Series I, 8.49% due October 14, 2024 Form 10-K
and all additional series unless for 1994
supplemented.
4.9 Indenture of Mortgage and Deed
of Trust dated December 1,
1952 of E&H Exhibit 4.5 to
relating to all series unless Registration
supplemented. Statement 2-49218
4.10 Third Supplemental Indenture
dated June 1, 1964 relating
to E&H's First Mortgage Bonds, Series D, Exhibit 4.5 to
4 3/4% due June 1, 1994 and all Registration
additional series unless supplemented. Statement 2-49218
4.11 Fourth Supplemental Indenture
dated January 15, 1968 relating to
E&H's First Mortgage Bonds, Series E, Exhibit 4.6 to
6 3/4% due January 15, 1998 and Registration
all additional series unless supplemented. Statement 2-49218
4.12 Fifth Supplemental Indenture
dated November 15, 1971 relating
to E&H's First Mortgage Bonds, Series F, Exhibit 4.7 to
8.70% due November 15, 2001 and Registration
all additional series unless supplemented. Statement 2-49218
4.13 Sixth Supplemental Indenture
dated April 1, 1974 relating to
E&H's First Mortgage Bonds, Series G, 8 7/8%
due April 1, 2004 and all additional
series unless supplemented. **
4.14 Seventh Supplemental Indenture
dated December 15, 1977 relating
to E&H's Exhibit 4 to
First Mortgage Bonds, Series H, Form 10-K
8.50% due December 15, 2002 and for 1977
all additional series unless supplemented. (File No. 0-7751)
4.15 Eighth Supplemental Indenture
dated October 29, 1987 relating
to E&H's First Mortgage Bonds, Series I, Exhibit 4.15 to
9.85% due October 15, 1997 and Form 10-K
all additional series unless supplemented. for 1987
4.16 Ninth Supplemental Indenture
dated August 29, 1991 relating
to E&H's
First Mortgage Bonds, Series J, Exhibit 4.18 to
9.43% due September 1, 2003 and Form 10-K
all additional series unless supplemented. for 1991
4.17 Tenth Supplemental Indenture
dated October 14, 1994 relating
to E&H's First Mortgage Bonds, Series K Exhibit 4.17 to
8.49% due October 14, 2024 and all Form 10-K
additional series unless supplemented. for 1994
4.18 Bond Purchase Agreement dated
August 29, 1991 relating to
E&H's Exhibit 4.19 to
First Mortgage Bonds, Series J Form 10-K
9.43% due September 1, 2003 for 1991
4.19 Purchase Agreement dated March 20,
1992 for the 8.55% Senior Notes Exhibit 4.18 to Form
due March 31, 2004 10-K for 1993
4.20 Note Agreement dated November 30,
1993 for the 6.75% Notes due Exhibit 4.18 to Form
November 30, 2023 10-K for 1993
4.21 First Mortgage Loan Agreement
dated October 24, 1988 with an
Institutional Investor in connection
with Unitil Realty Corp.'s Exhibit 4.16 to
acquisition of the Company's Form 10-K
facilities in Exeter, New Hampshire. for 1988
10.1 Labor Agreement effective June 1, 1994
between CECo and The
International Brotherhood of Electrical Exhibit 10.1 to Form
Workers, Local Union No. 1837 10-K for 1994
10.2 Labor Agreement effective June 25,
1995 between E&H and The International
Brotherhood of Electrical Workers, Local
Union No. 1837, Unit 1. Filed herewith
10.3 Labor Agreement effective May 1,
1994 between FG&E and The
Brotherhood of Utility Workers of Exhibit 10.3 to Form
New England, Inc., Local Union No. 340. 10-K for 1994
10.4 Unitil System Agreement dated
June 19, 1986 providing that Unitil Power Exhibit 10.9 to
will supply wholesale requirements electric Form 10-K
service to CECo and E&H for 1986
10.5 Supplement No. 1 to Unitil System
Agreement providing that Unitil
Power will supply wholesale Exhibit 10.8 to
requirements electric service to Form 10-K
CECo and E&H. for 1987
10.6 Transmission Agreement Between
Unitil Power Corp. and Public Exhibit 10.6 to
Service Company of New Hampshire, Form 10-K
Effective November 11, 1992 for 1993
10.7 Form of Severance Agreement
dated February 21, 1989, Exhibit 10.55 to
between the Company and Form 8
the persons named in the dated
schedule attached thereto. April 12, 1989
10.8 Key Employee Stock Option Exhibit 10.56 to
Plan effective as of Form 8 dated
January 17, 1989. April 12, 1989
10.9 Unitil Corporation Key Employee Exhibit 10.63 to
Stock Option Plan Award Form 10-K
Agreement. for 1989
10.10 Unitil Corporation Management Exhibit 10.94 to
Performance Compensation Program. Form 10-K/A for 1993
10.11 Unitil Corporation Supplemental
Executive Retirement Plan Exhibit 10.95 to
effective as of January 1, 1987. Form 10-K/A for 1993
11.1 Statement Re Computation in
Support of Earnings Per Share
for the Company Filed herewith
12.1 Statement Re Computation in
Support of Ratio of Earnings
to Fixed Charges for the Company. Filed herewith
21.1 Statement Re Subsidiaries of
Registrant. Filed herewith
27 Financial Data Schedule Filed herewith
99.1 1996 Proxy Statement Filed herewith
* The exhibits referred to in this column by specific designations and
dates have heretofore been filed with the Securities and Exchange Commission
under such designations and are hereby incorporated by reference.
** Copies of these debt instruments will be furnished to the Securities and
Exchange Commission upon request.
(b) Report on Form 8-K
No reports on Form 8-K were filed during the fourth quarter of the year
ended December 31, 1996.
CONSENT OF INDEPENDENT CERTIFIED PUBLIC ACCOUNTANTS
We have issued our report dated February 7, 1997, accompanying the
consolidated financial statements and schedule included in the Annual
Report of Unitil Corporation and subsidiaries on Form 10-K for the year
ended December 31, 1996. We hereby consent to the incorporation by
reference of said report in the Registration Statements of Unitil
Corporation and subsidiaries on Form S-3 and on Form S-8.
GRANT THORNTON LLP
Boston, Massachusetts
March 28, 1997
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, as amended, the Registrant has duly caused this report
to be signed on its behalf by the undersigned thereunto duly authorized.
Unitil Corporation
Date March 20, 1997 By Peter J. Stulgis
Peter J. Stulgis
Chairman of the Board of Directors,
and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934,
as amended, this report has been signed below by the following persons on
behalf of the Registrant and in the capacities and on the dates indicated.
Signature Capacity Date
Peter J. Stulgis Principal Executive March 20, 1997
Peter J. Stulgis Officer; Director
(Chairman of the Board of Directors
and Chief Executive Officer)
Michael J. Dalton Principal Operating March 20, 1997
Michael J. Dalton Officer; Director
(President and Chief
Operating Officer)
Gail A. Siart Principal Financial March 20, 1997
Gail A. Siart Officer
(Treasurer and Chief
Financial Officer)
G. Arnold Haynes Director March 20, 1997
G. Arnold Haynes
J. Parker Rice, Jr. Director March 20, 1997
J. Parker Rice, Jr.
Charles H. Tenney III Director March 20, 1997
Charles H. Tenney III
Franklin Wyman, Jr. Director March 20, 1997
Franklin Wyman, Jr.
SCHEDULE VIII.
UNITIL CORPORATION
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
Column A Column B Column C Column D Column E
Additions
Balance at Charged to Charged to Deductions Balance at
Beginning Costs and Other from End of
Description of Period Expenses Accounts (A) Reserves (B) Period
Year Ended December 31, 1996
Reserves Deducted from A/R
Electric 490,272 691,880 155,853 819,399 518,606
Gas 132,324 213,258 44,949 249,023 141,508
622,596 905,138 200,802 1,068,422 660,114
Year Ended December 31, 1995
Reserves Deducted from A/R
Electric 504,790 627,197 170,563 812,278 490,272
Gas 69,059 254,387 49,271 240,393 132,324
573,849 881,584 219,834 1,052,671 622,596
Year Ended December 31, 1994
Reserves Deducted from A/R
Electric 510,853 552,905 193,202 752,170 504,790
Gas 70,402 157,098 58,714 217,155 69,059
581,255 710,003 251,916 969,325 573,849
(A) Collections on Accounts Previously Charged Off
(B) Bad Debts Charged Off